UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year endedDecember 31, 2004
or

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number 1-16459Kinder Morgan Management, LLC(Exact name of registrant as specified in its charter)

Delaware

76-0669886

(State or other jurisdiction
of incorporation or organization)

(I.R.S. Employer
Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices,
including zip code)

Registrant's telephone number, including area code (713) 369-9000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Name of each exchange
on which registered

Shares Representing Limited
Liability Company Interests

New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act:

None

(Title of class)

Indicate by check mark whether the registrant (1)
has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days: Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.

In this report, unless the context requires otherwise, references to
"we," "us," "our," or the "Company" are intended
to mean Kinder Morgan Management, LLC and its consolidated subsidiary. Our shares
representing limited liability company interests are traded on the New York Stock Exchange
under the symbol "KMR". Our executive offices are located at 500 Dallas Street,
Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

We are a publicly traded Delaware limited liability company that was
formed on February 14, 2001. We are a limited partner in Kinder Morgan Energy Partners,
L.P., and manage and control its business and affairs pursuant to a delegation of control
agreement. Pursuant to this delegation of control agreement among Kinder Morgan G.P.,
Inc., Kinder Morgan Energy Partners, L.P., Kinder Morgan Energy Partners, L.P.'s operating
partnerships and us:



Kinder Morgan G.P., Inc., as general
partner of Kinder Morgan Energy Partners, L.P., delegated to us, to the fullest extent
permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership
agreement, and we assumed, all of Kinder Morgan G.P., Inc.'s power and authority to manage
and control the business and affairs of Kinder Morgan Energy Partners, L.P. and Kinder
Morgan Energy Partners, L.P.'s operating partnerships; and



We have agreed that we will not take any
of the following actions without the approval of Kinder Morgan G.P., Inc.:

allow a sale or exchange of all or
substantially all of the assets of Kinder Morgan Energy Partners, L.P.,

--

dissolve or liquidate Kinder Morgan Energy
Partners, L.P.,

--

take any action requiring unitholder
approval,

--

call any meetings of the Kinder Morgan
Energy Partners, L.P. common unitholders,

--

take any action that, under the terms of
the partnership agreement of Kinder Morgan Energy Partners, L.P., must or should receive a
special approval of the conflicts and audit committee of Kinder Morgan G.P., Inc.,

--

take any action that, under the terms of
the partnership agreement of Kinder Morgan Energy Partners, L.P., cannot be taken by the
general partner without the approval of all outstanding units,

3

--

settle or compromise any claim
or action directly against or otherwise relating to indemnification of our or the general
partner's (and respective affiliates) officers, directors, managers or members or relating
to our structure or securities,

--

settle or compromise any claim
or action relating to the i-units, which are a separate class of Kinder Morgan Energy
Partners, L.P.'s limited partnership interests, our shares or any offering of our shares,

--

settle or compromise any claim
or action involving tax matters,

--

allow Kinder Morgan Energy
Partners, L.P. to incur indebtedness if the aggregate amount of its indebtedness then
exceeds 50% of the market value of the then outstanding units of Kinder Morgan Energy
Partners, L.P., or

--

allow Kinder Morgan Energy
Partners, L.P. to issue units in one transaction, or in a series of related transactions,
having a market value in excess of 20% of the market value of then outstanding units of
Kinder Morgan Energy Partners, L.P.



Kinder Morgan G.P., Inc.:

--

is not relieved of any
responsibilities or obligations to Kinder Morgan Energy Partners, L.P. or its unitholders
as a result of such delegation,

--

owns, or one of its affiliates owns, all of our voting
shares, and

--

will not withdraw as general
partner of Kinder Morgan Energy Partners, L.P. or transfer to a non-affiliate all of its
interest as general partner, unless approved by both the holders of a majority of each of
the i-units and the holders of a majority of all units voting as a single class, excluding
common units and Class B units held by Kinder Morgan G.P., Inc. and its affiliates and
excluding the number of i-units corresponding to the number of our shares owned by Kinder
Morgan G.P., Inc. and its affiliates.



Kinder Morgan Energy Partners, L.P. has
agreed to:

--

recognize the delegation of rights and powers to us,

--

indemnify and protect us and
our officers and directors to the same extent as it does with respect to Kinder Morgan
G.P., Inc. as general partner, and

--

reimburse our expenses to the
same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner.

These agreements will continue until either Kinder Morgan G.P., Inc.
has withdrawn or been removed as the general partner of Kinder Morgan Energy Partners,
L.P. or all of our shares are owned by Kinder Morgan, Inc. and its affiliates. The
partnership agreement of Kinder Morgan Energy Partners, L.P. reflects these agreements.
These agreements also apply to the operating partnerships of Kinder Morgan Energy
Partners, L.P. and their partnership agreements.

Kinder Morgan G.P., Inc. remains the only general partner of Kinder
Morgan Energy Partners, L.P. and all of its operating partnerships. Kinder Morgan G.P.,
Inc. will retain all of its general partner interests and shares in the profits, losses
and distributions from all of these partnerships.

4

The withdrawal or removal of Kinder Morgan G.P., Inc. as general
partner of Kinder Morgan Energy Partners, L.P. will simultaneously result in the
termination of our power and authority to manage and control the business and affairs of
Kinder Morgan Energy Partners, L.P. Similarly, if Kinder Morgan G.P., Inc.'s power and
authority as general partner are modified in the partnership agreement of Kinder Morgan
Energy Partners, L.P., then the power and authority delegated to us will be modified on
the same basis. The delegation of control agreement can be amended by all parties to the
agreement, but on any amendment that would reduce the time for any notice to which owners
of our shares are entitled or would have a material adverse effect on our shares, as
determined by our board of directors in its discretion, the approval of the owners of a
majority of the shares, excluding shares owned by Kinder Morgan, Inc. and its affiliates,
is required.

Through our ownership of i-units, we are a limited partner in Kinder
Morgan Energy Partners, L.P. We do not expect to have any cash flow attributable to our
ownership of the i-units, but we expect that we will receive quarterly distributions of
additional i-units from Kinder Morgan Energy Partners, L.P. The number of additional
i-units we receive will be based on the amount of cash to be distributed by Kinder Morgan
Energy Partners, L.P. to an owner of a common unit. The amount of cash distributed by
Kinder Morgan Energy Partners, L.P. to its owners of common units is dependent on the
operations of Kinder Morgan Energy Partners, L.P. and its operating limited partnerships
and subsidiaries, and will be determined in accordance with its partnership agreement.

We have elected to be treated as a corporation for federal income tax
purposes. Because we are treated as a corporation for federal income tax purposes, an
owner of our shares will not report on its federal income tax return any of our items of
income, gain, loss and deduction relating to an investment in us.

We are subject to federal income tax on our taxable income; however,
the i-units owned by us generally are not entitled to allocations of income, gain, loss or
deduction of Kinder Morgan Energy Partners, L.P. until such time as there is a liquidation
of Kinder Morgan Energy Partners, L.P. Therefore, we do not anticipate that we will have
material amounts of taxable income resulting from our ownership of the i-units unless we
enter into a sale or exchange of the i-units or Kinder Morgan Energy Partners, L.P. is
liquidated.

We have no properties. Our assets consist of a small amount of working
capital and the i-units that we own.

We have no employees. For more information, see Note 4 of the
accompanying Notes to Consolidated Financial Statements and Kinder Morgan Energy Partners,
L.P.'s report on Form 10-K for the year ended December 31, 2004.

We make available free of charge on or through our Internet website, at
http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such material with, or furnish it to,
the Securities and Exchange Commission.

Our shares are listed for trading on the New York Stock Exchange under
the symbol "KMR." The per share high and low sale prices of our shares, as
reported on the New York Stock Exchange, by quarter for the last two years are provided
below.

Market PricePer Share

2004

2003

Low

High

Low

High

Quarter Ended:

March 31

$39.72

$44.50

$30.00

$34.09

June 30

$34.25

$42.86

$32.01

$37.55

September 30

$36.25

$41.52

$36.26

$38.57

December 31

$39.28

$42.39

$37.45

$43.65

There were approximately 18,000 holders of our listed shares as of
February 3, 2005, which includes individual participants in security position listings.

Under the terms of our limited liability company agreement, except in
connection with our liquidation, we do not pay distributions on our shares in cash but we
make distributions on our shares in additional shares or fractions of shares. At the same
time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and
i-units, we distribute on each of our shares that fraction of a share determined by
dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners,
L.P. on each common unit by the average market price of a share determined for the
ten-trading day period ending on the trading day immediately prior to the ex-dividend date
for our shares.

Share Distributions

Shares Distributed Per Outstanding Share

Equivalent Distribution Value Per Share1

Total Number of Additional Shares Distributed

Quarter Ended:

2004

2003

2004

2003

2004

2003

March 31

0.017412

0.018488

$ 0.69

$ 0.64

872,958

859,933

June 30

0.018039

0.017138

$ 0.71

$ 0.65

920,140

811,878

September 30

0.017892

0.016844

$ 0.73

$ 0.66

929,105

811,625

December 31

0.017651

0.015885

$ 0.74

$ 0.68

955,936

778,309

______________

1

This is the cash
distribution paid or payable to each common unit of Kinder Morgan Energy Partners, L.P.
for the quarter indicated and is used to calculate our distribution of shares as discussed
above. Because of this calculation, the market value of the shares distributed on the date
of distribution may be less or more than the cash distribution per common unit of Kinder
Morgan Energy Partners, L.P.

There were no sales of unregistered equity securities during the
periods covered by this report. We did not repurchase any shares during the fourth quarter
of 2004.

This is the amount of cash
distributions payable to each common unit of Kinder Morgan Energy Partners, L.P. for each
period shown. Under the terms of our limited liability company agreement, except in
connection with our liquidation, we do not pay distributions on our shares in cash but we
make distributions on our shares in additional shares or fractions of shares. At the same
time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and
i-units, we distribute on each of our shares that fraction of a share determined by
dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners,
L.P. on each common unit by the average market price of a share determined for a
ten-trading day period ending on the trading day immediately prior to the ex-dividend date
for our shares. Because of this calculation, the market value of the shares distributed on
the date of distribution may be less or more than the cash distribution per common unit of
Kinder Morgan Energy Partners, L.P.

Item 7.Management's Discussion and Analysis of
Financial Condition and Results of Operations.

General

We are a publicly traded Delaware limited liability company, formed on
February 14, 2001, that has elected to be treated as a corporation for federal income tax
purposes. Our voting shares are owned by Kinder Morgan, G.P., Inc., an indirect wholly
owned subsidiary of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy
Partners, L.P. Kinder Morgan, Inc. is one of the largest energy storage and transportation
companies in the United States, operating, either for itself or on behalf of Kinder Morgan
Energy Partners, L.P., over 35,000 miles of natural gas and refined petroleum products
pipelines and approximately 135 terminals. Kinder Morgan Energy Partners, L.P. is one of
the largest publicly traded pipeline limited partnerships in the United States in terms of
market capitalization and the owner and operator of the largest independent refined
petroleum products pipeline system in the United States in terms of volumes delivered.
Kinder Morgan Energy Partners, L.P. owns and/or operates a diverse group of assets used in
the transportation, storage and processing of energy products, including refined petroleum
products pipeline systems with more than 10,000 miles of products pipeline and 60
associated terminals. Kinder Morgan Energy Partners, L.P. owns approximately 14,000 miles
of natural gas transportation pipelines, plus natural gas gathering and storage
facilities. Kinder Morgan Energy Partners, L.P. also owns or operates approximately 75
liquid and bulk terminal facilities and more than 55 rail transloading facilities located
throughout the United States, handling approximately 68 million tons of coal, petroleum
coke and other dry-bulk materials annually and having a liquids storage capacity of
approximately 37 million barrels for refined petroleum products, chemicals and other
liquid products. In addition, Kinder Morgan Energy Partners, L.P. owns Kinder Morgan CO2
Company, L.P., which transports, markets and produces carbon dioxide for use in enhanced
oil recovery operations and owns

7

interests in and/or operates six oil fields in West Texas, all of which
are using or have used carbon dioxide injection operations. Kinder Morgan CO2
Company, L.P. also owns and operates the Wink Pipeline, a crude oil pipeline in West
Texas.

We are a limited partner in Kinder Morgan Energy Partners, L.P., and
manage and control its business and affairs pursuant to a delegation of control agreement.
Our success is dependent upon our operation and management of Kinder Morgan Energy
Partners, L.P. and its resulting performance. Therefore, we have attached as Annex A
hereto Kinder Morgan Energy Partners, L.P.'s 2004 Annual Report on Form 10-K. The
following discussion should be read in conjunction with the accompanying financial
statements and related notes.

Business

Kinder Morgan G.P., Inc. has delegated to us, to the fullest extent
permitted under Delaware law and Kinder Morgan Energy Partners, L.P.'s limited partnership
agreement, all of its rights and powers to manage and control the business and affairs of
Kinder Morgan Energy Partners, L.P. subject to Kinder Morgan G.P., Inc.'s right to approve
specified actions.

Results of Operations

Our results of operations consist of the offsetting expenses and
revenues associated with our managing and controlling the business and affairs of Kinder
Morgan Energy Partners, L.P. and our equity in the earnings of Kinder Morgan Energy
Partners, L.P. attributable to the i-units we own. At December 31, 2004, through our
ownership of i-units, we owned approximately 26.2% of all of Kinder Morgan Energy
Partners, L.P.'s outstanding limited partner interests. We use the equity method of
accounting for our investment in Kinder Morgan Energy Partners, L.P. and, therefore, we
record earnings equal to approximately 26.2% of Kinder Morgan Energy Partners, L.P.'s
limited partners' net income. Our percentage ownership in Kinder Morgan Energy Partners,
L.P. will change over time upon the distribution of additional i-units to us or upon
issuances of additional common units or other equity securities by Kinder Morgan Energy
Partners, L.P.

For the years ended December 31, 2004, 2003 and 2002, Kinder Morgan
Energy Partners, L.P. reported limited partners' net income of $436.5 million, $370.8
million and $337.6 million, respectively. Our net income for the corresponding periods was
$75.1 million, $58.8 million and $45.3 million, respectively. The reported segment
earnings contribution by business segment for Kinder Morgan Energy Partners, L.P. is set
forth below. This information should be read in conjunction with Kinder Morgan Energy
Partners, L.P.'s 2004 Annual Report on Form 10-K, which is attached hereto as Annex A.

Kinder Morgan Energy Partners, L.P.

Year Ended December 31,

2004

2003

2002

(In
thousands)

Segment Earnings Contribution:

Product Pipelines

$ 370,321

$ 370,974

$ 343,935

Natural Gas Pipelines

364,872

319,288

276,766

CO2

234,258

140,755

100,983

Terminals

238,848

203,701

194,917

Total Segment
Earnings

1,208,299

1,034,718

916,601

Interest and Corporate Administrative
Expenses1

(376,721)

(337,381)

(308,224)

Net Income

$ 831,578

$ 697,337

$ 608,377

==========

==========

=========

1

Includes interest and debt
expense, general and administrative expenses, minority interest expense and other
insignificant items.

8

Our earnings, as reported in the accompanying Consolidated Statements
of Income, represent equity in earnings of Kinder Morgan Energy Partners, L.P.
attributable to the i-units that we own, reduced by a deferred income tax provision. The
deferred income tax provision is calculated based on the book/tax basis difference created
by our recognition, under accounting principles generally accepted in the United States of
America, of our share of the earnings of Kinder Morgan Energy Partners, L.P. Our earnings
per share (both basic and diluted) is our net income divided by our weighted-average
number of outstanding shares during the periods presented. There are no securities
outstanding that may be converted into or exercised for shares.

Income Taxes

We are a limited liability company that has elected to be treated as a
corporation for federal income tax purposes. Deferred income tax assets and liabilities
are recognized for temporary differences between the basis of our assets and liabilities
for financial reporting and tax purposes. Changes in tax legislation are included in the
relevant computations in the period in which such changes are effective. Currently, our
only such temporary difference results from recognition of the increased investment
associated with recording our equity in the earnings of Kinder Morgan Energy Partners,
L.P. The effective tax rate used in computing our income tax provision was 33.8% for 2004,
38% for 2003 and 37.2% for 2002. The effective tax rate for 2004 and 2002 was reduced by
2.5% and 0.8%, respectively, due to a reduction in the state tax rate on our cumulative
deferred tax liability.

We are a party to a tax indemnification agreement with Kinder Morgan,
Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to
indemnify us for any tax liability attributable to our formation or our management and
control of the business and affairs of Kinder Morgan Energy Partners, L.P., and for any
taxes arising out of a transaction involving the i-units we own to the extent the
transaction does not generate sufficient cash to pay our taxes with respect to such
transaction.

Liquidity and Capital Resources

Our authorized capital structure consists of two classes of interests:
(1) our listed shares and (2) our voting shares, collectively referred to in this document
as our "shares." Additional classes of interests may be approved by our board
and holders of a majority of our shares, excluding shares held by Kinder Morgan, Inc. and
its affiliates. Our only off-balance sheet arrangement is our equity investment in Kinder
Morgan Energy Partners, L.P.

The number of our shares outstanding will at all times equal the number
of i-units of Kinder Morgan Energy Partners, L.P. we own. Under the terms of our limited
liability company agreement, except in connection with our liquidation, we do not pay
distributions on our shares in cash but we make distributions on our shares in additional
shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes
a distribution on its common units and i-units, we distribute on each of our shares that
fraction of a share determined by dividing the amount of the cash distribution to be made
by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of
a share determined for a ten-trading day period ending on the trading day immediately
prior to the ex-dividend date for our shares.

On February 14, 2005, we paid a share distribution of 0.017651 shares
per outstanding share (955,936 total shares) to shareholders of record as of January 31,
2005, based on the $0.74 per common unit distribution declared by Kinder Morgan Energy
Partners, L.P. This distribution is paid in the form of additional shares or fractions
thereof based on the average market price of a share determined for a ten-trading day
period ending on the trading day immediately prior to the ex-dividend date for our shares.

9

We expect that our expenditures associated with managing and
controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and the
reimbursement for these expenditures received by us from Kinder Morgan Energy Partners,
L.P. will continue to be equal. As stated above, the distributions we expect to receive on
the i-units we own will be in the form of additional i-units. Therefore, we expect neither
to generate nor to require significant amounts of cash in ongoing operations. We currently
have no debt and have no plans to incur any debt. Any cash received from the sale of
additional shares will immediately be used to purchase additional i-units. Accordingly, we
do not anticipate any other sources or needs for additional liquidity.

Our success is dependent upon our operation and management of Kinder
Morgan Energy Partners, L.P. and its resulting performance. We are a limited
partner in Kinder Morgan Energy Partners, L.P. In the event that Kinder Morgan Energy
Partners, L.P. decreases its cash distributions to its common unitholders, distributions
of i-units on the i-units that we own will decrease correspondingly, and distributions of
additional shares to owners of our shares will decrease as well. The risk factors that
affect Kinder Morgan Energy Partners, L.P. also affect us; see "Risk Factors"
for Kinder Morgan Energy Partners, L.P. included in Annex A.

The value of the quarterly per-share distribution of an additional
fractional share may be less than the cash distribution on a common unit of Kinder Morgan
Energy Partners, L.P. The fraction of a Kinder Morgan Management, LLC share to be
issued in distributions per share outstanding will be based on the average closing price
of the shares for the ten consecutive trading days preceding the ex-dividend date. Because
the market price of our shares may vary substantially over time, the market value of our
shares on the date a shareholder receives a distribution of additional shares may vary
substantially from the cash the shareholder would have received had the shareholder owned
common units instead of shares.

Kinder Morgan Energy Partners, L.P. could be treated as a corporation
for United States federal income tax purposes. The treatment of Kinder Morgan Energy
Partners, L.P. as a corporation would substantially reduce the cash distributions on the
common units and the value of i-units that Kinder Morgan Energy Partners, L.P. will
distribute quarterly to us and the value of our shares that we will distribute quarterly
to our shareholders. The anticipated benefit of an investment in our shares
depends largely on the treatment of Kinder Morgan Energy Partners, L.P. as a partnership
for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. has not
requested, and does not plan to request, a ruling from the Internal Revenue Service on
this or any other matter affecting Kinder Morgan Energy Partners, L.P. Current law
requires Kinder Morgan Energy Partners, L.P. to derive at least 90% of its annual gross
income from specific activities to continue to be treated as a partnership for United
States federal income tax purposes. Kinder Morgan Energy Partners, L.P. may not find it
possible, regardless of its efforts, to meet this income requirement or may inadvertently
fail to meet this income requirement. Current law may change so as to cause Kinder Morgan
Energy Partners, L.P. to be treated as a corporation for United States federal income tax
purposes without regard to its sources of income or otherwise subject Kinder Morgan Energy
Partners, L.P. to entity-level taxation.

If Kinder Morgan Energy Partners, L.P. were to be treated as a
corporation for United States federal income tax purposes, it would pay United States
federal income tax on its income at the corporate tax

10

rate, which is currently a maximum of 35%, and would pay state income
taxes at varying rates. Distributions to us of additional i-units would generally be taxed
as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy
Partners, L.P. as a corporation, the cash available for distribution to a common
unitholder would be substantially reduced, which would reduce the values of i-units
distributed quarterly to us and our shares distributed quarterly to our shareholders.
Treatment of Kinder Morgan Energy Partners, L.P. as a corporation would cause a
substantial reduction in the value of our shares.

As an owner of i-units, we may not receive value equivalent to the
common unit value for our i-unit interest in Kinder Morgan Energy Partners, L.P. if Kinder
Morgan Energy Partners, L.P. is liquidated. As a result, a shareholder may receive less
per share in our liquidation than is received by an owner of a common unit in a
liquidation of Kinder Morgan Energy Partners, L.P. If Kinder Morgan Energy
Partners, L.P. is liquidated and Kinder Morgan, Inc. does not satisfy its obligation to
purchase your shares, which is triggered by a liquidation, then the value of your shares
will depend on the after-tax amount of the liquidating distribution received by us as the
owner of i-units. The terms of the i-units provide that no allocations of income, gain,
loss or deduction will be made in respect of the i-units until such time as there is a
liquidation of Kinder Morgan Energy Partners, L.P. If there is a liquidation of Kinder
Morgan Energy Partners, L.P., it is intended that we will receive allocations of income
and gain in an amount necessary for the capital account attributable to each i-unit to be
equal to that of a common unit. As a result, we will likely realize taxable income upon
the liquidation of Kinder Morgan Energy Partners, L.P. However, there may not be
sufficient amounts of income and gain to cause the capital account attributable to each
i-unit to be equal to that of a common unit. If they are not equal, we, and therefore our
shareholders, will receive less value than would be received by an owner of common units.

Further, the tax indemnity provided to us by Kinder Morgan, Inc. only
indemnifies us for our tax liabilities to the extent we have not received sufficient cash
in the transaction generating the tax liability to pay the associated tax. Prior to any
liquidation of Kinder Morgan Energy Partners, L.P., we do not expect to receive cash in a
taxable transaction. If a liquidation of Kinder Morgan Energy Partners, L.P. occurs,
however, we likely would receive cash which would need to be used at least in part to pay
taxes. As a result, our residual value and the value of our shares likely will be less
than the value of the common units upon the liquidation of Kinder Morgan Energy Partners,
L.P.

Our management and control of the business and affairs of Kinder Morgan
Energy Partners, L.P. and its operating partnerships could result in our being liable for
obligations to third parties who transact business with Kinder Morgan Energy Partners,
L.P. and its operating partnerships and to whom we held ourselves out as a general
partner. We could also be responsible for environmental costs and liabilities
associated with Kinder Morgan Energy Partners, L.P.'s assets in the event that it is not
able to perform all of its obligations under environmental laws. Kinder Morgan
Energy Partners, L.P. may not be able to reimburse or indemnify us as a result of its
insolvency or bankruptcy. The primary adverse impact of that insolvency or bankruptcy on
us would be the decline in or elimination of the value of our i-units, which are our only
significant assets. Assuming under these circumstances that we have some residual value in
our i-units, a direct claim by creditors of Kinder Morgan Energy Partners, L.P. against us
could further reduce our net asset value and cause us also to declare bankruptcy. Another
risk with respect to third party claims will occur, however, under the circumstances when
Kinder Morgan Energy Partners, L.P. is financially able to pay us, but for some other
reason does not reimburse or indemnify us. For example, to the extent that Kinder Morgan
Energy Partners, L.P. fails to satisfy any environmental liabilities for which it is
responsible, we could be held liable under environmental laws. For additional information,
see the following risk factor.

11

If we are not fully indemnified by Kinder Morgan Energy Partners, L.P.
for all the liabilities we incur in performing our obligations under the delegation of
control agreement, we could face material difficulties in paying those liabilities, and
the net value of our assets could be adversely affected. Under the delegation of
control agreement, we have been delegated management and control of the business and
affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships. There are
circumstances under which we may not be indemnified by Kinder Morgan Energy Partners, L.P.
or Kinder Morgan G.P., Inc. for liabilities we incur in managing and controlling the
business and affairs of Kinder Morgan Energy Partners, L.P. These circumstances include:



if we act in bad faith; and



if we breach laws like the federal
securities laws, where indemnification may not be allowed.

If in the future we cease to manage and control the business and
affairs of Kinder Morgan Energy Partners, L.P., we may be deemed to be an investment
company for purposes of the Investment Company Act of 1940. In that event, we
would either have to register as an investment company under the Investment Company Act,
obtain exemptive relief from the Securities and Exchange Commission, or modify our
organizational structure or our contract rights to fall outside the definition of an
investment company. Registering as an investment company could, among other things,
materially limit our ability to engage in transactions with our affiliates, including the
purchase and sale of certain securities or other property to or from our affiliates,
restrict our ability to borrow funds or engage in other transactions involving leverage,
and require us to add directors who are independent of us or our affiliates.

The interests of Kinder Morgan, Inc. may differ from our interests, the
interests of our shareholders and the interests of unitholders of Kinder Morgan Energy
Partners, L.P. Kinder Morgan, Inc. owns all of the stock of the general partner of
Kinder Morgan Energy Partners, L.P. and elects all of its directors. The general partner
of Kinder Morgan Energy Partners, L.P. owns all of our voting shares and elects all of our
directors. Furthermore, some of our directors and officers are also directors and officers
of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. and
have fiduciary duties to manage the businesses of Kinder Morgan, Inc. and Kinder Morgan
Energy Partners, L.P. in a manner that may not be in the best interest of our
shareholders. Kinder Morgan, Inc. has a number of interests that differ from the interests
of our shareholders and the interests of the unitholders. As a result, there is a risk
that important business decisions will not be made in the best interest of our
shareholders.

Our limited liability company agreement restricts or eliminates a
number of the fiduciary duties that would otherwise be owed by our board of directors to
our shareholders, and the partnership agreement of Kinder Morgan Energy Partners, L.P.
restricts or eliminates a number of the fiduciary duties that would otherwise be owed by
the general partner to the unitholders. Modifications of state law standards of
fiduciary duties may significantly limit the ability of our shareholders and the
unitholders to successfully challenge the actions of our board of directors and the
general partner, respectively, in the event of a breach of their fiduciary duties. These
state law standards include the duties of care and loyalty. The duty of loyalty, in the
absence of a provision in the limited liability company agreement or the limited
partnership agreement to the contrary, would generally prohibit our board of directors or
the general partner from taking any action or engaging in any transaction as to which it
has a conflict of interest. Our limited liability company and the limited partnership
agreement of Kinder Morgan Energy Partners, L.P. contain provisions that prohibit our
shareholders and the limited partners, respectively, from advancing claims that otherwise
might raise issues as to compliance with fiduciary duties or applicable law. For example,
the limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides that the
general partner may take into account the interests of parties other than Kinder Morgan
Energy Partners, L.P. in resolving conflicts of interest. Further, it provides that in the
absence of bad faith by the general partner, the resolution of a conflict by the general

12

partner will not be a breach of any duty. The provisions relating to
the general partner apply equally to us as its delegate. Our limited liability company
agreement provides that none of our directors or officers will be liable to us or any
other person for any acts or omissions if they acted in good faith.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to historical or
current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast,"
"strategy," "position," "continue," "estimate,"
"expect," "may," or the negative of those terms or other variations of
them or comparable terminology. In particular, statements, express or implied, concerning
future actions, conditions or events, future operating results or the ability to generate
sales, income or cash flow or to make distributions are forward-looking statements.
Forward-looking statements are not guarantees of performance. They involve risks,
uncertainties and assumptions. Future actions, conditions or events and future results of
our operations and those of Kinder Morgan Energy Partners, L.P. may differ materially from
those expressed in these forward-looking statements. Please see "Information
Regarding Forward-Looking Statements" for Kinder Morgan Energy Partners, L.P.
included in Annex A. Many of the factors that will determine these results are beyond our
ability to control or predict. Specific factors that could cause actual results to differ
from those in the forward-looking statements include:

Kinder Morgan
Energy Partners, L.P.'s ability to acquire new businesses and assets and integrate those
operations into its existing operations, as well as its ability to make expansions to its
facilities;



difficulties
or delays experienced by railroads, barges, trucks, ships or pipelines in delivering
products to or from Kinder Morgan Energy Partners, L.P.'s terminals or pipelines;



Kinder Morgan
Energy Partners, L.P.'s ability to successfully identify and close acquisitions and make
cost-saving changes in operations;



shut-downs or
cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military
bases or other businesses that use Kinder Morgan Energy Partners, L.P.'s services or
provide services or products to Kinder Morgan Energy Partners, L.P.;



changes in
laws or regulations, third-party relations and approvals, decisions of courts, regulators
and governmental bodies that may adversely affect Kinder Morgan Energy Partners, L.P.'s
business or its ability to compete;



our ability to
offer and sell equity securities and Kinder Morgan Energy Partners, L.P.'s ability to
offer and sell equity securities and debt securities or obtain debt financing in
sufficient amounts to implement that portion of Kinder Morgan Energy Partners, L.P.'s
business plan that contemplates growth through acquisitions of operating businesses and
assets and expansions of its facilities;

13



Kinder Morgan Energy Partners,
L.P.'s indebtedness could make it vulnerable to general adverse economic and industry
conditions, limit its ability to borrow additional funds and/or place it at competitive
disadvantages compared to its competitors that have less debt or have other adverse
consequences;



interruptions of electric
power supply to Kinder Morgan Energy Partners, L.P.'s facilities due to natural disasters,
power shortages, strikes, riots, terrorism, war or other causes;



our ability to obtain
insurance coverage without a significant level of self-retention of risk;

the timing and extent of
changes in commodity prices for oil, natural gas, electricity and certain agricultural
products;



the extent of Kinder Morgan
Energy Partners, L.P.'s success in discovering, developing and producing oil and gas
reserves, including the risks inherent in exploration and development drilling, well
completion and other development activities;



engineering and mechanical or
technological difficulties that Kinder Morgan Energy Partners, L.P. may experience with
operational equipment, in well completions and workovers, and in drilling new wells;



the uncertainty inherent in
estimating future oil and natural gas production or reserves that Kinder Morgan Energy
Partners, L.P. may experience;



the timing and success of
Kinder Morgan Energy Partners, L.P.'s business development efforts; and



unfavorable results of
litigation involving Kinder Morgan Energy Partners, L.P. and the fruition of contingencies
referred to in Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for the
year ended December 31, 2004.

You should not put undue reliance on any forward-looking statements.
See Item 7 "Management's Discussion and Analysis of Financial Condition and Results
of Operations - Risk Factors of our Business" for a more detailed description of
these and other factors that may affect the forward-looking statements. When considering
forward-looking statements, one should keep in mind the risk factors described in
"Risk Factors of our Business" above. The risk factors could cause our actual
results to differ materially from those contained in any forward-looking statement. We
disclaim any obligation to

14

update the above list or to announce publicly the result of any
revisions to any of the forward-looking statements to reflect future events or
developments.

To the Board of Directors
and Stockholders of Kinder Morgan Management, LLC

We have completed an integrated audit of Kinder Morgan Management, LLC's 2004
consolidated financial statements and of its internal control over financial reporting as
of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in
accordance with the standards of the Public Company Accounting Oversight Board (United
States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Management, LLC and its subsidiary at December 31, 2004 and 2003, and the results
of their operations and their cash flows for each of the three years in the period ended
December 31, 2004 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in accordance
with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit of financial
statements includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management's assessment, included in Management's Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the Company
maintained effective internal control over financial reporting as of December 31, 2004
based on criteria established in Internal Control - Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly
stated, in all material respects, based on those criteria. Furthermore, in our opinion,
the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2004, based on criteria established in Internal
Control - Integrated Framework issued by the COSO. The Company's management is
responsible for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting. Our
responsibility is to express opinions on management's assessment and on the effectiveness
of the Company's internal control over financial reporting based on our audit. We
conducted our audit of internal control over financial reporting in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes obtaining an
understanding of internal control over financial reporting, evaluating management's
assessment, testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation
of financial statements for

17

external purposes in accordance with generally accepted accounting principles. A
company's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company's assets that could have a
material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures
may deteriorate.

Kinder Morgan Management, LLC is a publicly traded Delaware limited
liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., an
indirect wholly owned subsidiary of Kinder Morgan, Inc., (a midstream energy company
traded on the New York Stock Exchange under the symbol "KMI"), owns all of our
voting shares. References to "we," "our" or "the Company"
are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary.

2. Significant Accounting Policies

(A) Basis of Presentation

Our consolidated financial statements include the accounts of Kinder
Morgan Management, LLC and its wholly owned subsidiary, Kinder Morgan Services LLC. All
material intercompany transactions and balances have been eliminated.

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires management to make
estimates and assumptions. These estimates and assumptions affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities, and the
reported amounts of revenues and expenses. Actual results could differ from these
estimates.

(B) Accounting for Investment in Kinder Morgan Energy Partners, L.P.

We use the equity method of accounting for our investment in Kinder
Morgan Energy Partners, L.P., which investment is further described in Notes 3 and 4.
Kinder Morgan Energy Partners, L.P. is a publicly traded limited partnership and is traded
on the New York Stock Exchange under the symbol "KMP." We record, in the period
in which it is earned, our share of the earnings of Kinder Morgan Energy Partners, L.P.
attributable to the i-units we own. We receive distributions from Kinder Morgan Energy
Partners, L.P. in the form of additional i-units, which increase the number of i-units we
own. We issue additional shares (or fractions thereof) of the Company to our existing
shareholders in an amount equal to the additional i-units received from Kinder Morgan
Energy Partners, L.P. At December 31, 2004, through our ownership of i-units, we owned
approximately 26.2% of all of Kinder Morgan Energy Partners, L.P.'s outstanding limited
partner interests.

We adjust the carrying value of our investment when an equity method
investee or a consolidated subsidiary issues additional equity (or reacquires equity
shares) in any manner that alters our ownership percentage. Differences between the per
unit sales proceeds from these equity issuances (or costs for reacquisitions) and our
underlying book basis are recorded directly to paid-in capital rather than being
recognized as gains or losses. See Note 3 for a discussion of several such transactions.

(C) Accounting for Share Distributions

Our board of directors declares and we make additional share
distributions at the same times that Kinder Morgan Energy Partners, L.P. declares and
makes distributions on the i-units to us, so that the number of i-units we own and the
number of our shares outstanding remain equal. We account for the share distributions we
make by charging retained earnings and crediting outstanding shares with amounts that
equal the number of shares distributed multiplied by the closing price of the shares on
the date the distribution is payable. As a result, we expect that our retained earnings
will always be in a deficit

23

position because (i) distributions per unit for Kinder Morgan Energy
Partners, L.P. (which serve to reduce our retained earnings) are based on earnings plus
depreciation, depletion and amortization minus sustaining capital expenditures, which
amount generally exceeds the earnings per unit (which serve to increase our retained
earnings) and (ii) the impact on our retained earnings attributable to our equity in the
earnings of Kinder Morgan Energy Partners, L.P. is recorded after a provision for income
taxes.

(D) Earnings Per Share

Both basic and diluted earnings per share are computed based on the
weighted-average number of shares outstanding during each period, adjusted for share
splits. There are no securities outstanding that may be converted into or exercised for
shares.

(E) Income Taxes

We are a limited liability company that has elected to be treated as a
corporation for federal income tax purposes. Deferred income tax assets and liabilities
are recognized for temporary differences between the basis of our assets and liabilities
for financial reporting and tax purposes. We include changes in tax legislation in the
relevant computations in the period in which such changes are effective.

Our long-term deferred income tax liability of $82.6 million and $64.5
million at December 31, 2004 and 2003, respectively, results from recognition of the
increased investment associated with recording our equity in the earnings of Kinder Morgan
Energy Partners, L.P. The effective tax rate utilized in computing our income tax
provision was 33.8% for 2004, 38% for 2003 and 37.2% for 2002. The effective tax rate
includes the 35% federal statutory rate, a provision for state income taxes and a
reduction of 2.5% in 2004 and 0.8% in 2002 due to a reduction in the state tax rate on our
cumulative deferred tax liability.

We entered into a tax indemnification agreement with Kinder Morgan,
Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to
indemnify us for any tax liability attributable to our formation or our management and
control of the business and affairs of Kinder Morgan Energy Partners, L.P. and for any
taxes arising out of a transaction involving the i-units we own to the extent the
transaction does not generate sufficient cash to pay our taxes with respect to such
transaction.

(F) Cash Flow Information

We consider all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. No cash payments for interest or
income taxes were made during the periods presented.

3. Capitalization

Our authorized capital structure consists of two classes of interests:
(1) our listed shares and (2) our voting shares, collectively referred to in this document
as our "shares." Prior to the May 2001 initial public offering of our shares,
our issued capitalization consisted of $100,000 contributed by Kinder Morgan, G.P., Inc.
for two voting shares. At December 31, 2004, Kinder Morgan, Inc. owned approximately 15.1
million, or approximately 27.9% of our outstanding shares.

In February 2004, Kinder Morgan Energy Partners, L.P. issued 5.3
million common units in a public offering at a price of $46.80 per common unit, receiving
total net proceeds (after underwriting discount) of $237.8 million. We did not acquire any
of these common units. On March 25, 2004, we closed the issuance and sale of 360,664 of
our listed shares in a limited registered offering. None of the shares from our offering
were purchased by Kinder Morgan, Inc. We used the net proceeds of approximately $14.9

24

million from the offering to buy additional i-units from Kinder Morgan
Energy Partners, L.P. In November 2004, Kinder Morgan Energy Partners, L.P. issued 5.5
million common units in a public offering at a price of $46.00 per common unit. An
additional 0.6 million common units were issued by Kinder Morgan Energy Partners, L.P. in
December 2004 in order to meet the underwriters' over-allotment option. Kinder Morgan
Energy Partners, L.P. received total net proceeds (after underwriting discount) from these
offerings of $268.3 million. We did not acquire any of these common units. Also in
November 2004, we closed the issuance and sale of 1.3 million of our listed shares in a
limited registered offering. None of the shares from our offering were purchased by Kinder
Morgan, Inc. We used the net proceeds of approximately $52.6 million from the offering to
buy additional i-units from Kinder Morgan Energy Partners, L.P. These issuances,
collectively, changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and
had the associated effects of increasing our (i) investment in the net assets of Kinder
Morgan Energy Partners, L.P. by $23.6 million, (ii) associated accumulated deferred income
taxes by $8.6 million and (iii) paid-in capital by $15.0 million. See Note 1(B).

In June 2003, Kinder Morgan Energy Partners, L.P. issued 4.6 million
common units in a public offering at a price of $39.35 per common unit, receiving total
net proceeds (after underwriting discount) of $173.3 million. We did not acquire any of
these common units. This issuance of common units by Kinder Morgan Energy Partners, L.P.
changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and had the
associated effects of increasing our (i) investment in the net assets of Kinder Morgan
Energy Partners by $6.4 million, (ii) associated accumulated deferred income taxes by $2.4
million and (iii) paid-in capital by $4.0 million. See Note 1(B).

On February 14, 2005, we paid a share distribution of 0.017651 shares
per outstanding share (955,936 total shares) to shareholders of record as of January 31,
2005, based on the $0.74 per common unit distribution declared by Kinder Morgan Energy
Partners, L.P. This distribution is paid in the form of additional shares or fractions
thereof based on the average market price of a share determined for a ten-trading day
period ending on the trading day immediately prior to the ex-dividend date for our shares.

4. Business Activities and Related Party Transactions

At no time after our formation and prior to our initial public offering
did we have any operations or own any interest in Kinder Morgan Energy Partners, L.P. Upon
the closing of our initial public offering in May 2001, we became a limited partner in
Kinder Morgan Energy Partners, L.P. and, pursuant to a delegation of control agreement, we
assumed the management and control of its business and affairs. Under the delegation of
control agreement, Kinder Morgan G.P., Inc. delegated to us, to the fullest extent
permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership
agreement, all of Kinder Morgan G.P., Inc.'s power and authority to manage and control the
business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan
G.P., Inc.'s right to approve certain transactions. Kinder Morgan Energy Partners, L.P.
will either pay directly or reimburse us for all expenses we incur in performing under the
delegation of control agreement and will be obligated to indemnify us against claims and
liabilities provided that we have acted in good faith and in a manner we believed to be
in, or not opposed to, the best interests of Kinder Morgan Energy Partners, L.P. and the
indemnity is not prohibited by law. Kinder Morgan Energy Partners, L.P. consented to the
terms of the delegation of control agreement including Kinder Morgan Energy Partners,
L.P.'s indemnity and reimbursement obligations. We do not receive a fee for our service
under the delegation of control agreement, nor do we receive any margin or profit on the
expense reimbursement. We incurred approximately $132.2 million, $111.4 million and $106.9
million of expenses during the years ended December 31, 2004, 2003 and 2002, respectively,
on behalf of Kinder Morgan Energy Partners, L.P. The expense reimbursements received from
Kinder Morgan Energy Partners, L.P. are accounted for as a reduction to the expense
incurred. The net monthly balance payable or receivable from these activities is settled
in cash in the following month.

25

Kinder Morgan Services LLC is our wholly owned subsidiary and provides
centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder
Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating
partnerships and subsidiaries (collectively, the "Group"). Employees of KMGP
Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., are assigned to work for
one or more members of the Group. When they do so, they remain under our ultimate
management and control. The direct costs of all compensation, benefits expenses, employer
taxes and other employer expenses for these employees are allocated and charged by Kinder
Morgan Services LLC to the appropriate members of the Group, and the members of the Group
reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs.
There is no profit or margin charged by Kinder Morgan Services LLC to the members of the
Group. The administrative support necessary to implement these payroll and benefits
services is provided by the human resource department of Kinder Morgan, Inc., and the
related administrative costs are allocated to members of the Group in accordance with
expense allocation procedures. The effect of these arrangements is that each member of the
Group bears the direct compensation and employee benefits costs of its assigned or
partially assigned employees, as the case may be, while also bearing its allocable share
of administrative costs. Pursuant to its limited partnership agreement, Kinder Morgan
Energy Partners, L.P. reimburses Kinder Morgan Services LLC for its share of these
administrative costs, and such reimbursements are accounted for as described above.

Following is summarized financial information for Kinder Morgan Energy
Partners, L.P., a publicly traded limited partnership in which we own a significant
interest. Additional information on Kinder Morgan Energy Partners, L.P.'s results of
operations and financial position are contained in its 2004 Annual Report on Form 10-K,
which is attached to this report as Annex A.

Summarized Income Statement Information

Year Ended December 31,

2004

2003

2002

(In
thousands)

Operating Revenues

$ 7,932,861

$ 6,624,322

$ 4,237,057

Operating Expenses

6,958,865

5,817,633

3,512,759

Operating Income

$ 973,996

$ 806,689

$ 724,298

===========

===========

===========

Income Before Cumulative Effect of a
Change in Accounting Principle

$ 831,578

$ 693,872

$ 608,377

===========

===========

===========

Net Income

$ 831,578

$ 697,337

$ 608,377

===========

===========

===========

Summarized Balance Sheet Information

As of December 31,

2004

2003

(In
thousands)

Current Assets

$ 853,171

$ 705,522

============

============

Noncurrent Assets

$ 9,699,771

$ 8,433,660

============

============

Current Liabilities

$ 1,180,855

$ 804,379

============

============

Noncurrent Liabilities

$ 5,429,921

$ 4,783,812

============

============

Minority Interest

$ 45,646

$ 40,064

============

============

26

6. Recent Accounting Pronouncements

In January 2004, the FASB issued FASB Staff Position ("FSP")
FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the "Act"). This FSP
permits a sponsor of a postretirement health care plan that provides a prescription drug
benefit to make a one-time election to postpone accounting for the effects of the Act.
Regardless of whether a company elects that deferral, the FSP requires certain disclosures
pending further consideration of the underlying accounting issues. In May 2004, the FASB
issued FSP FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003, which superseded FSP FAS
106-1 effective July 1, 2004. FSP FAS 106-2 provides transitional guidance for accounting
for the effects of the Act on the accumulated projected benefit obligation and periodic
postretirement health care benefit expense. We have no employees.

In December 2004, the FASB issued SFAS No. 123R (revised 2004), Share-Based
Payment. This Statement amends SFAS No. 123, Accounting for Stock-Based
Compensation, and requires companies to expense the value of employee stock options
and similar awards. Significant provisions of SFAS No. 123R include the following:



share-based payment awards result in a cost that will be
measured at fair value on the awards' grant date, based on the estimated number of awards
that are expected to vest. Compensation cost for awards that vest would not be reversed if
the awards expire without being exercised;



when measuring fair value, companies can choose an
option-pricing model that appropriately reflects their specific circumstances and the
economics of their transactions;



companies will recognize compensation cost for share-based
payment awards as they vest, including the related tax effects. Upon settlement of
share-based payment awards, the tax effects will be recognized in the income statement or
additional paid-in capital; and



public companies are allowed to select from three alternative
transition methods - each having different reporting implications.

In October 2004, the FASB decided to delay by six months the effective
date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is
now effective for public companies for interim and annual periods beginning after June 15,
2005. Public companies with calendar year-ends will be required to adopt SFAS No. 123R in
the third quarter of 2005. We currently have no share-based compensation plans.

We do not expect these pronouncements to have a significant impact on
our financial statements, except for any impacts that may result from changes in our
equity in earnings of Kinder Morgan Energy Partners, L.P. as a result of its adoption of
these pronouncements.

Estimates of proved reserves are subject to change, either positively
or negatively, as additional information becomes available and contractual and economic
conditions change. Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known

28

reservoirs under existing economic and operating conditions, that is,
prices and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions. Proved developed reserves are the quantities of
crude oil, natural gas liquids and natural gas expected to be recovered through existing
investments in wells and field infrastructure under current operating conditions. Proved
undeveloped reserves require additional investments in wells and related infrastructure in
order to recover the production.

The standardized measure of discounted cash flows is based on
assumptions including year-end market pricing, future development and production costs and
projections of future abandonment costs. A discount factor of 10% is applied annually to
the future net cash flows.

As of December 31, 2004, our management, including our Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the
Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of human error
and the circumvention or overriding of the controls and procedures. Accordingly, even
effective disclosure controls and procedures can only provide reasonable assurance of
achieving their control objectives. Based upon and as of the date of the evaluation, our
Chief Executive Officer and our Chief Financial Officer concluded that the design and
operation of our disclosure controls and procedures were effective in all material
respects to provide reasonable assurance that information required to be disclosed in the
reports we file and submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported as and when required.

Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Under the supervision and with the participation
of our management, including our principal executive officer and principal financial
officer, we conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on
our evaluation under the framework in Internal Control - Integrated Framework issued
by the COSO, our management concluded that our internal control over financial reporting
was effective as of December 31, 2004.

Our management's assessment of the effectiveness of our internal
control over financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in
their report which is included herein.

There has been no change in our internal control over financial
reporting during the fourth quarter of 2004 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.

Set forth below is certain information concerning our directors and
executive officers. All directors are elected annually by, and may be removed by, Kinder
Morgan G.P., Inc. as the sole holder of our voting shares. All officers serve at the
discretion of our board of directors. In addition to the individuals named below, Kinder
Morgan, Inc. was one of our directors until its resignation in January 2003.

Name

Age

Position

Richard D. Kinder

60

Director, Chairman, Chief Executive Officer and President

C. Park Shaper

36

Director, Executive Vice President and Chief Financial
Officer

Edward O. Gaylord

73

Director

Gary L. Hultquist

61

Director

Perry M. Waughtal

69

Director

Thomas A. Bannigan

51

Vice President (President, Products Pipelines)

Richard T. Bradley

49

Vice President (President, CO2)

David D. Kinder

30

Vice President, Corporate Development

Joseph Listengart

36

Vice President, General Counsel and Secretary

Deborah A. Macdonald

53

Vice President (President, Natural Gas Pipelines)

Jeffrey R. Armstrong

36

Vice President (President, Terminals)

James E. Street

48

Vice President, Human Resources and Administration

Richard D. Kinder is Director, Chairman, Chief Executive Officer
and President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder
Morgan, Inc. Mr. Kinder was elected President of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2004. Mr. Kinder has served as Director,
Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation
in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder
Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive
Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is the uncle of David
Kinder, Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Kinder Morgan, Inc.

C. Park Shaper is Director, Executive Vice President and Chief
Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and
Executive Vice President and Chief Financial Officer of Kinder Morgan, Inc. Mr. Shaper was
elected Executive Vice President of Kinder Morgan Management, LLC, Kinder Morgan G.P.,
Inc. and Kinder Morgan, Inc. in July 2004, and was elected Director of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice
President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its
formation in February 2001, and served as Treasurer of Kinder Morgan Management, LLC from
February 2001 to January 2004. He has served as Treasurer of Kinder Morgan, Inc. from
April 2000 to January 2004 and Vice President and Chief Financial Officer of Kinder
Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and
Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as
Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. He received a
Masters in Business Administration degree from the J.L. Kellogg Graduate School of
Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in
Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from
Stanford University.

Edward O. Gaylord is a Director of Kinder Morgan Management, LLC
and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management,
LLC upon its formation in February

31

2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in
February 1997. Since 1989, Mr. Gaylord has been the Chairman of the Board of Directors of
Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship
channel.

Gary L. Hultquist is a Director of Kinder Morgan Management, LLC
and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of Kinder Morgan
Management, LLC upon its formation in February 2001. He was elected Director of Kinder
Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing
Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory
firm.

Perry M. Waughtal is a Director of Kinder Morgan Management, LLC
and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of Kinder Morgan
Management, LLC upon its formation in February 2001. Mr. Waughtal was elected Director of
Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of
Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr.
Waughtal is also a director of HealthTronics, Inc.

Thomas A. Bannigan is Vice President (President, Products
Pipelines) of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and President and
Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected Vice
President (President, Products Pipelines) of Kinder Morgan Management, LLC upon its
formation in February 2001. He was elected Vice President (President, Products Pipelines)
of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has served as President and
Chief Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan
received his Juris Doctor, cum laude, from Loyola University in 1980 and received a
Bachelors degree from the State University of New York in Buffalo.

Richard T. Bradley is Vice President (President, CO2)
of Kinder Morgan Management, LLC and of Kinder Morgan G.P., Inc. and President of Kinder
Morgan CO2 Company, L.P. Mr. Bradley was elected Vice President
(President, CO2) of Kinder Morgan Management, LLC upon its
formation in February 2001 and Vice President (President, CO2)
of Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan
CO2 Company, L.P. (formerly known as Shell CO2
Company, Ltd.) since March 1998. Mr. Bradley received a Bachelor of Science in Petroleum
Engineering from the University of Missouri at Rolla.

David D. Kinder is Vice President, Corporate Development of Kinder
Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was
elected Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of
corporate development for Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January
2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance
from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.

Joseph Listengart is Vice President, General Counsel and Secretary
of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr.
Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC upon its formation in February 2001. He was elected Vice President and
General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and
Secretary of Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Kinder Morgan
G.P., Inc.'s Secretary in November 1998 and has been an employee of Kinder Morgan G.P.,
Inc. since March 1998. Mr. Listengart received his Masters in Business Administration from
Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston
University in May 1994, and his Bachelor of Arts degree in Economics from Stanford
University in June 1990.

32

Deborah A. Macdonald is Vice President (President, Natural Gas
Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan,
Inc. She was elected Vice President (President, Natural Gas Pipelines) of Kinder Morgan
Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in June 2002. Ms.
Macdonald served as President of Natural Gas Pipeline Company of America from October 1999
to March 2003. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton
University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton
University in December 1972.

Jeffrey R. Armstrong is Vice President (President, Terminals) of
Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Armstrong became Vice
President (President, Terminals) in July 2003. He served as President, Kinder Morgan
Liquids Terminals LLC from March 1, 2001, when the company was formed via the acquisition
of GATX Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX
Terminals, where he was General Manager of their East Coast operations. He received his
bachelor's degree from the United States Merchant Marine Academy and an MBA from the
University of Notre Dame.

James E. Street is Vice President, Human Resources and
Administration of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder
Morgan, Inc. Mr. Street was elected Vice President, Human Resources and Administration of
Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice
President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder
Morgan, Inc. in August 1999. Mr. Street received a Masters of Business Administration
degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the
University of Nebraska at Kearney.

Corporate Governance

Pursuant to a delegation of control agreement among Kinder Morgan
Energy Partners, L.P., its general partner, us and others, we manage and control the
business and affairs of Kinder Morgan Energy Partners, L.P., except that we cannot take
certain specified actions without the approval of Kinder Morgan Energy Partners, L.P.'s
general partner. The limited partnership agreement of Kinder Morgan Energy Partners, L.P.
provides for a general partner of the Partnership rather than a board of directors.
Through the operation of Kinder Morgan Energy Partners, L.P.'s limited partnership
agreement and the delegation of control agreement, our board of directors performs the
functions of and is the equivalent of a board of directors of Kinder Morgan Energy
Partners, L.P. Similarly, the standing committees of our board function as standing
committees of the board of Kinder Morgan Energy Partners, L.P. Our board of directors is
comprised of the same persons who comprise Kinder Morgan Energy Partners, L.P.'s general
partner's board of directors. References in this report to the board mean our board acting
as the delegate of and as the board of directors of Kinder Morgan Energy Partners, L.P.'s
general partner, and references to committees mean committees of the board acting as the
delegate of and as the committees of the board of directors of Kinder Morgan Energy
Partners, L.P.'s general partner.

The board has adopted governance guidelines for the board and charters
for the audit committee, nominating and governance committee and compensation committee.
The governance guidelines and the rules of the New York Stock Exchange require that a
majority of the directors be independent, as described in those guidelines and rules
respectively. To assist in making determinations of independence, the board has determined
that the following categories of relationships are not material relationships that would
cause the affected director not to be independent:



If the director was an employee, or had an immediate family
member who was an executive officer, of us or Kinder Morgan Energy Partners, L.P. or any
of its affiliates, but the employment relationship ended more than three years prior to
the date of determination (or, in the case of employment of a director as an interim
chairman, interim chief executive

33

officer or interim executive officer, such employment
relationship ended by the date of determination);



If during any twelve month period within the three years
prior to the determination the director received no more than, and has no immediate family
member that received more than, $100,000 in direct compensation from Kinder Morgan Energy
Partners, L.P. or its affiliates, other than (i) director and committee fees and
pension or other forms of deferred compensation for prior service (provided such
compensation is not contingent in any way on continued service), (ii) compensation
received by a director for former service as an interim chairman, interim chief executive
officer or interim executive officer, and (iii) compensation received by an immediate
family member for service as an employee (other than an executive officer);



If the director is at the date of determination a current
employee, or has an immediate family member that is at the date of determination a current
executive officer, of another company that has made payments to, or received payments
from, Kinder Morgan Energy Partners, L.P. and its affiliates for property or services in
an amount which, in each of the three fiscal years prior to the date of determination, was
less than the greater of $1.0 million or 2% of such other company's annual
consolidated gross revenues. Contributions to tax-exempt organizations are not considered
payments for purposes of this determination;



If the director is also a director, but is not an employee or
executive officer, of Kinder Morgan Energy Partners, L.P.'s general partner or another
affiliate or affiliates of us or Kinder Morgan Energy Partners, L.P., so long as such
director is otherwise independent; and



If the director beneficially owns less than 10% of each class
of voting securities of us, Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. or
its general partner.

The board has affirmatively determined that Messrs. Gaylord, Hultquist
and Waughtal, who constitute a majority of the directors, are independent as described in
our governance guidelines and the New York Stock Exchange rules. Each of them meets the
standards above and has no other relationship with us. In conjunction with regular
quarterly and special board meetings, these three non-management directors also meet in
executive session without members of management. In December 2004, Mr. Gaylord was elected
for a one year term to serve as lead director to develop the agendas for and moderate
these executive sessions of independent directors.

We have a separately designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of
Messrs. Gaylord, Hultquist and Waughtal. Mr. Waughtal is the chairman of the audit
committee and has been determined by the board to be an "audit committee financial
expert." The governance guidelines and our audit committee charter, as well as the
rules of the New York Stock Exchange and the Securities and Exchange Commission, require
that members of the audit committee satisfy independence requirements in addition to those
above. The board has determined that all of the members of the audit committee are
independent as described under the relevant standards.

We have not, nor has Kinder Morgan Energy Partners, L.P. nor its
general partner made, within the preceding three years, contributions to any tax-exempt
organization in which any of our or Kinder Morgan Energy Partners, L.P.'s independent
directors serves as an executive officer that in any single fiscal year exceeded the
greater of $1 million or 2% of such tax-exempt organization's consolidated gross revenues.

On September 3, 2004, our chief executive officer certified to the New
York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of

34

September 3, 2004, he was not aware of any violation by us of the New
York Stock Exchange's Corporate Governance listing standards. We have also filed as an
exhibit to this report the Sarbanes-Oxley Act Section 302 certifications regarding the
quality of our public disclosure.

We make available free of charge within the "Investors"
information section of our internet website, at www.kindermorgan.com, and in print to any
shareholder who requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of business
conduct and ethics (which applies to senior financial officers and the chief executive
officer, among others). Requests for copies may be directed to Investor Relations, Kinder
Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone
(713) 369-9490. We intend to disclose any amendments to our code of business conduct and
ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of
that code granted to our executive officers or directors that would otherwise be disclosed
on Form 8-K on our internet website within five business days following such amendment or
waiver. The information contained on or connected to our internet website is not
incorporated by reference into this Form 10-K and should not be considered part of this or
any other report that we file with or furnish to the Securities and Exchange Commission.

You may contact our lead director, the chairpersons of any of the
board's committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002,
Attention: General Counsel, or by e-mail within the "Contact Us" section of our
internet website, at www.kindermorgan.com. Your communication should specify the
intended recipient.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16 of the Securities Exchange Act of 1934 requires our
directors and officers, and persons who own more than 10% of a registered class of our
equity securities, to file initial reports of ownership and reports of changes in
ownership with the Securities and Exchange Commission. Such persons are required by
Securities and Exchange Commission regulation to furnish us with copies of all Section
16(a) forms they file.

Based solely on our review of the copies of such forms furnished to us
and written representations from our executive officers and directors, we believe that all
Section 16(a) filing requirements were met during 2004.

All of our individual executive officers and directors serve in the
same capacities for Kinder Morgan G.P., Inc. Certain of those executive officers,
including all of the named officers below, also serve as executive officers of Kinder
Morgan, Inc. All information in this report with respect to compensation of executive
officers describes the total compensation received by those persons in all capacities for
Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and their
respective affiliates.

Summary Compensation Table

Annual Compensation

Long-term
Compensation Awards

Name and Principal Position

Year

Salary

Bonus1

Restricted
Stock
Awards2

Kinder Morgan, Inc. Shares Underlying
Options

All Other
Compensation3

Richard D. Kinder

2004

$ 1

$ -

$ -

-

$ -

Director, Chairman,

2003

1

-

-

-

-

CEO
and President

2002

1

-

-

-

-

C. Park Shaper

2004

200,000

975,000

-

-

8,378

Director,
Executive Vice

2003

200,000

875,000

5,918,000

-

8,378

President
and CFO

2002

200,000

950,000

-

100,0004

8,336

Deborah A. Macdonald
Vice President,

2004

200,000

975,000

-

-

8,966

(President, Natural

2003

200,000

875,000

5,380,000

-

8,966

Gas Pipelines)

2002

200,000

950,000

-

50,0005

8,966

Joseph Listengart

2004

200,000

875,000

-

-

8,378

Vice
President, General

2003

200,000

825,000

3,766,000

-

8,378

Counsel and
Secretary

2002

200,000

950,000

-

-

8,336

Richard T. Bradley, Vice

2004

200,000

560,000

-

-

8,630

President,
(President CO

2)

2003

200,000

525,000

2,152,000

-

8,606

2002

200,000

500,000

-

-

8,606

___________

1

Amounts earned in year
shown and paid the following year.

2

Represent shares of
restricted Kinder Morgan, Inc. stock awarded in 2003. The awards were issued under a
shareholder approved plan. For the 2003 awards, value computed as the number of shares
awarded times the closing price on date of grant ($53.80 at July 16, 2003). Twenty-five
percent of the shares in each grant vest on the third anniversary after the date of grant
and the remaining seventy-five percent of the shares in each grant vest on the fifth
anniversary after the date of grant. To vest, Kinder Morgan Energy Partners, L.P. and/or
Kinder Morgan, Inc. must also achieve one of the following performance hurdles during the
vesting period: (i) Kinder Morgan, Inc. must earn $3.70 per share in any fiscal year; (ii)
Kinder Morgan Energy Partners, L.P. must distribute $2.72 over four consecutive quarters;
(iii) fund at least one year's annual incentive program; or (iv) Kinder Morgan, Inc.'s
stock price must average over $60.00 per share during any consecutive 30-day period. All
of these hurdles have been met. The 2003 awards were long-term equity compensation for our
current senior management through July 2008, and neither Kinder Morgan Energy Partners,
L.P. nor Kinder Morgan, Inc. intend to make further restricted stock awards or other
long-term equity grants to them before that date. The holders of the restricted stock
awards are eligible to vote and to receive dividends declared on such shares.

The 100,000 options to purchase Kinder Morgan,
Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share
and vest at the rate of twenty-five percent on each of the first four anniversaries after
the date of grant.

5

The 50,000 options to purchase Kinder Morgan,
Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share
and vest at the rate of twenty-five percent on each of the first four anniversaries after
the date of grant.

Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a
defined contribution 401(k) plan. The plan permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of base
compensation, on a pre-tax basis, into participant accounts. In

36

addition to a mandatory contribution equal to 4% of base compensation
per year for most plan participants, Kinder Morgan G.P., Inc. may make discretionary
contributions in years when specific performance objectives are met. Certain employees'
contributions are based on collective bargaining agreements. The mandatory contributions
are made each pay period on behalf of each eligible employee. Any discretionary
contributions are made during the first quarter following the performance year. All
employer contributions, including discretionary contributions, are in the form of Kinder
Morgan, Inc. stock that is immediately convertible into other available investment
vehicles at the employee's discretion. During the first quarter of 2005, we will not make
any discretionary contributions to individual accounts for 2004. For employees hired on or
prior to December 31, 2004, all contributions, together with earnings thereon, are
immediately vested and not subject to forfeiture. Employer contributions for employees
hired on or after January 1, 2005 will vest on the second anniversary of the date of hire.
Participants may direct the investment of their contributions into a variety of
investments. Plan assets are held and distributed pursuant to a trust agreement. Because
levels of future compensation, participant contributions and investment yields cannot be
reliably predicted over the span of time contemplated by a plan of this nature, it is
impractical to estimate the annual benefits payable at retirement to the individuals
listed in the Summary Compensation Table above.

At its July 2004 meeting, the Compensation Committee of the Kinder
Morgan, Inc. Board of Directors approved that contingent upon its approval at its July
2005 meeting, each eligible employee will receive an additional 1% company contribution
based on eligible base pay to his or her Savings Plan account each pay period beginning
with the first pay period after the July 2005 Committee meeting. The 1% contribution will
be in the form of Kinder Morgan, Inc. common stock (the same as the current 4%
contribution). The 1% contribution will be in addition to, and does not change or
otherwise impact, the annual 4% contribution that eligible employees currently receive. It
may be converted to any other Savings Plan investment fund at any time and it will vest on
the second anniversary of the employee's date of hire. Since this additional 1% company
contribution is discretionary, Compensation Committee approval will be required annually
for each contribution.

Common Unit Option Plan.Pursuant
to Kinder Morgan Energy Partners, L.P.'s Common Unit Option Plan, key personnel are
eligible to receive grants of options to acquire common units. The total number of common
units authorized under the option plan is 500,000. None of the options granted under the
option plan may be "incentive stock options" under Section 422 of the Internal
Revenue Code. If an option expires without being exercised, the number of common units
covered by such option will be available for a future award. The exercise price for an
option may not be less than the fair market value of a common unit on the date of grant.
Kinder Morgan Management, LLC's compensation committee administers the option plan, and
the plan has a termination date of March 5, 2008.

No individual employee may be granted options for more than 20,000
common units in any year. Kinder Morgan Management, LLC's compensation committee will
determine the duration and vesting of the options to employees at the time of grant. As of
December 31, 2004, options to purchase 95,400 common units are currently outstanding and
held by 30 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder
Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will vest on the
first anniversary of the date of grant and twenty percent on each of the next three
anniversaries. The options expire seven years from the date of grant. As of December 31,
2004, all 95,400 outstanding options were fully vested.

The option plan also granted to each of Kinder Morgan G.P., Inc.'s
non-employee directors an option to purchase 10,000 common units at an exercise price
equal to the fair market value of the common units at the end of the trading day on such
date. Under this provision, as of December 31, 2004, options to purchase 20,000 common
units are currently outstanding and held by two of Kinder Morgan G.P., Inc.'s three
non-employee directors. Forty percent of all such options will vest on the first
anniversary of the date of grant and twenty percent on each of the next three
anniversaries. The non-employee director

37

options will expire seven years from the date of grant. As of December
31, 2004, all 20,000 outstanding options were fully vested.

No options to purchase common units were granted during 2004 to any of
the individuals named in the Summary Compensation Table above. The following table sets
forth certain information as of December 31, 2004 and for the fiscal year then ended with
respect to common unit options previously granted to the individuals named in the Summary
Compensation Table above. Mr. Listengart is the only person named in the Summary
Compensation Table who has been granted common unit options. No common unit options were
granted at an option price below the fair market value on the date of grant.

Kinder Morgan, Inc. Stock Plan. Under Kinder Morgan,
Inc.'s stock plan, employees of Kinder Morgan, Inc. and its affiliates, including
employees of Kinder Morgan, Inc.'s direct and indirect subsidiaries, like KMGP Services
Company, Inc., are eligible to receive grants of restricted Kinder Morgan, Inc. stock and
grants of options to acquire shares of common stock of Kinder Morgan, Inc. The
Compensation Committee of Kinder Morgan, Inc.'s board of directors administers this plan.
The primary purpose for granting restricted Kinder Morgan, Inc. stock and Kinder Morgan,
Inc. stock options under this plan to employees of Kinder Morgan, Inc., KMGP Services
Company, Inc. and Kinder Morgan Energy Partners, L.P.'s subsidiaries is to provide them
with an incentive to increase the value of the common stock of Kinder Morgan, Inc. A
secondary purpose of the grants is to provide compensation to those employees for services
rendered to Kinder Morgan Energy Partners, L.P. and its subsidiaries. During 2004, none of
the persons named in the Summary Compensation Table above were granted Kinder Morgan, Inc.
stock options.

Calculated on the basis of
the fair market value of the underlying shares at year-end, minus the exercise price.

Cash Balance Retirement Plan.Employees
of KMGP Services Company, Inc. and Kinder Morgan, Inc. are also eligible to participate in
a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a
career-pay formula, "grandfathered" according to age and years of service on
December 31, 2000, or collective bargaining arrangements. All other employees accrue
benefits through a personal retirement account in the Cash Balance Retirement Plan.
Employees with prior service and not grandfathered converted to the Cash Balance
Retirement Plan on January 1, 2001, and were credited with the current fair value of any
benefits they had previously accrued through the defined benefit plan.

38

Under the plan, we make contributions on behalf of participating
employees equal to 3% of eligible compensation every pay period. In addition,
discretionary contributions are made to the plan based on the performance of Kinder
Morgan, Inc. and Kinder Morgan Energy Partners, L.P. No discretionary contributions were
made for 2004 performance. Interest is credited to the personal retirement accounts at the
30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees
become fully vested in the plan after five years, and they may take a lump sum
distribution upon termination of employment or retirement.

The following table sets forth the estimated annual benefits payable as
of December 31, 2004, under normal retirement at age sixty-five, assuming current
remuneration levels without any salary projection, and participation until normal
retirement at age sixty-five, with respect to the named executive officers under the
provisions of the Kinder Morgan Cash Balance Retirement Plan. These benefits are subject
to federal and state income taxes, where applicable, but are not subject to deduction for
social security or other offset amounts.

Name

Current Credited Years
of Service

Estimated Credited Years
of Service at Age 65

Age as of
Jan. 1, 2005

Current Compensation Covered by Plans

Estimated Annual Benefit Payable Upon Retirement1

Richard D. Kinder

4

8.8

60.2

$ 1

$ -

C. Park Shaper

4

32.7

36.4

200,000

62,363

Joseph Listengart

4

32.5

36.6

200,000

61,608

Deborah A. Macdonald

4

15.9

53.1

200,000

15,763

Richard T. Bradley

4

19.8

49.2

200,000

22,727

________

1

The estimated annual
benefits payable are based on the straight-life annuity form.

2000 Annual Incentive Plan. Effective January 20, 2000, Kinder
Morgan, Inc. established the 2000 Annual Incentive Plan of Kinder Morgan, Inc. The plan
was established, in part, to enable the portion of an officer's or other employee's annual
bonus based on objective performance criteria to qualify as "qualified
performance-based compensation" under the Internal Revenue Code. "Qualified
performance-based compensation" compensation is deductible for tax purposes. The plan
permits annual bonuses to be paid to Kinder Morgan, Inc.'s officers and other employees
and employees of Kinder Morgan, Inc.'s subsidiaries based on their individual performance,
Kinder Morgan, Inc.'s performance and the performance of Kinder Morgan, Inc.'s
subsidiaries. The plan is administered by the compensation committee of Kinder Morgan,
Inc.'s Board of Directors. Under the plan, at or before the start of each calendar year,
the compensation committee establishes written performance objectives. The performance
objectives are based on one or more criteria set forth in the plan. The compensation
committee may specify a minimum acceptable level of achievement of each performance
objective below which no bonus is payable with respect to that objective. The maximum
payout to any individual under the plan in any year is $1.5 million, and the compensation
committee has the discretion to reduce the bonus amount in any performance period. The
cash bonuses set forth in the Summary Compensation Table above were paid under the plan.
Awards may be granted under the plan for calendar years 2000 through 2005.

Directors Fees. Kinder Morgan Energy Partners, L.P.'s Directors'
Unit Appreciation Rights Plan, as discussed below, served as partial compensation for
non-employee directors for 2004. In addition to the awards provided by this plan, each
non-employee director received additional compensation of $10,000 in 2004, paid $2,500 per
quarter. Mr. Edward O. Gaylord, as chairman of our audit committee, received additional
compensation in the amount of $10,000, paid $2,500 per quarter. Mr. Perry M. Waughtal,
appointed as lead director in October 2003 by us and who served as lead director until
December 2004, received additional compensation in the amount of $25,000, paid $10,000 in
the first quarter and $5,000 in each of the last three quarters. In addition, directors
are reimbursed for reasonable expenses in connection with board meetings.

In January 2005, we terminated the Directors' Unit Appreciation Rights
Plan and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan
for Non-Employee Directors, as discussed below, to compensate non-employee directors for
2005.

Directors' Unit Appreciation Rights Plan. On April 1,
2003, our compensation committee established the Kinder Morgan Energy Partners, L.P.
Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of our three
non-employee directors was eligible to receive common unit appreciation rights. Upon the
exercise of unit appreciation rights, we will pay, within thirty days of the exercise
date, the participant an amount of cash equal to the excess, if any, of the aggregate fair
market value of the unit appreciation rights exercised as of the exercise date over the
aggregate award price of the rights exercised. The fair market value of one unit
appreciation right as of the exercise date will be equal to the closing price of one
common unit on the New York Stock Exchange on that date. The award price of one unit
appreciation right will be equal to the closing price of one common unit on the New York
Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit
appreciation right granted under the plan will be payable only in cash (that is, no
exercise will result in the issuance of additional common units) and will be evidenced by
a unit appreciation rights agreement.

All unit appreciation rights granted vest on the six-month anniversary
of the date of grant. If a unit appreciation right is not exercised in the ten year period
following the date of grant, the unit appreciation right will expire and not be
exercisable after the end of such period. In addition, if a participant ceases to serve on
the board for any reason prior to the vesting date of a unit appreciation right, such unit
appreciation right will immediately expire on the date of cessation of service and may not
be exercised.

On April 1, 2003, the date of adoption of the plan, each of our three
non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000
unit appreciation rights were granted to each of our three non-employee directors on
January 21, 2004, at the first meeting of the board in 2004. As of December 31, 2004,
52,500 unit appreciation rights had been granted. No unit appreciation rights were
exercised during 2004. During the first board meeting of 2005, the plan was terminated and
replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors; however, all unexercised awards made under the plan remain
outstanding.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors. On January 18, 2005, our compensation committee established
the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan compensate our
non-employee directors for 2005. The plan is administered by our compensation committee
and our board has sole discretion to terminate the plan at any time. The primary purpose
of this plan was to promote Kinder Morgan Energy Partners, L.P.'s interests and the
interests of Kinder Morgan Energy Partners, L.P.'s unitholders by aligning the
compensation of the non-employee members of our board of directors with unitholders'
interests. Further, since our success is dependent on our operation and management of
Kinder Morgan Energy Partners, L.P.'s business and its resulting performance, the plan is
expected to align the compensation of the non-employee members of the board with the
interests of our shareholders.

40

The plan recognizes that the compensation to be paid to each
non-employee director is fixed by our board, generally annually, and that the compensation
is expected to include an annual retainer payable in cash and other cash compensation.
Pursuant to the plan, in lieu of receiving the other cash compensation, each non-employee
director may elect to receive common units. Each election shall be generally at or around
the first board meeting in January of each calendar year and will be effective for the
entire calendar year. The initial election under this plan was made effective January 20,
2005. A non-employee director may make a new election each calendar year. The total number
of common units authorized under this compensation plan is 100,000.

Each annual election shall be evidenced by an agreement, the Common
Unit Compensation Agreement, between Kinder Morgan Energy Partners, L.P. and each
non-employee director, and this agreement will contain the terms and conditions of each
award. Pursuant to this agreement, all common units issued under this plan are subject to
forfeiture restrictions that expire six months from the date of issuance. Until the
forfeiture restrictions lapse, common units issued under the plan may not be sold,
assigned, transferred, exchanged, or pledged by a non-employee director. In the event the
director's service as a director of our board is terminated prior to the lapse of the
forfeiture restriction either for cause, or voluntary resignation, each director shall,
for no consideration, forfeit to Kinder Morgan Energy Partners, L.P. all common units to
the extent then subject to the forfeiture restrictions. Common units with respect to which
forfeiture restrictions have lapsed shall cease to be subject to any forfeiture
restrictions, and Kinder Morgan Energy Partners, L.P. will provide each director a
certificate representing the units as to which the forfeiture restrictions have lapsed. In
addition, each non-employee director shall have the right to receive distributions with
respect to the common units awarded to him under the plan, to vote such common units and
to enjoy all other unitholder rights, including during the period prior to the lapse of
the forfeiture restrictions.

The number of common units to be issued to a non-employee director
electing to receive the other cash compensation in the form of common units will equal
such other cash compensation awarded, divided by the closing price of the common units on
the New York Stock Exchange on the day the cash compensation is awarded (such price, the
fair market value), rounded down to the nearest 50 common units. The common units will be
issuable as specified in the Common Unit Compensation Agreement. A non-employee director
electing to receive the other cash compensation in the form of common units will receive
cash equal to the difference between (i) the other cash compensation awarded to such
non-employee director and (ii) the number of common units to be issued to such
non-employee director multiplied by the fair market value of a common unit. This cash
payment shall be payable in four equal installments (together with the annual cash
retainer) generally around March 31, June 30, September 30 and December 31 of the calendar
year in which such cash compensation is awarded.

On January 18, 2005, the date of adoption of the plan, each of our
three non-employee directors was awarded a cash retainer of $40,000 that will be paid
quarterly during 2005, and other cash compensation of $79,750. Effective January 20, 2005,
each non-employee director elected to receive the other cash compensation of $79,750 in
the form of Kinder Morgan Energy Partners, L.P. common units and was issued 1,750 common
units pursuant to the plan and its agreements (based on the $45.55 closing market price of
Kinder Morgan Energy Partners, L.P. common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other cash
compensation that did not equate to a whole common unit, based on the January 18, 2005
$45.55 closing price, will be paid to each of the non-employee directors as described
above. No other compensation is to be paid to the non-employee directors during 2005.

The following table sets forth information as of January 31, 2005,
regarding (a) the beneficial ownership of (i) Kinder Morgan Energy Partners, L.P.'s common
and Class B units, (ii) our shares and (iii) the common stock of Kinder Morgan, Inc., the
parent company of Kinder Morgan G.P., Inc., by all our directors and those of Kinder
Morgan G.P., Inc., by each of the named executive officers and by all our directors and
executive officers as a group and (b) the beneficial ownership of Kinder Morgan Energy
Partners, L.P.'s common and Class B units or our shares by all persons known by us to own
beneficially more than 5% of Kinder Morgan Energy Partners, L.P.'s common and Class B
units and our shares. Unless otherwise noted, the address of each person below is c/o
Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial Ownership1

Kinder
Morgan Energy Partners, L.P.

Kinder Morgan

Kinder
Morgan, Inc.

Common Units

Class B Units

Management, LLC Shares

Voting
Stock

Numberof Units2

Percentof Class

Numberof Units3

Percentof Class

Numberof Shares4

Percentof Class

Numberof Shares5

Percentof Class

Richard D. Kinder6

315,979

*

-

-

47,379

*

23,995,415

19.45%

C. Park Shaper7

4,000

*

-

-

2,534

*

326,808

*

Edward O. Gaylord8

34,750

*

-

-

-

-

2,000

*

Gary L. Hultquist9

11,750

*

-

-

-

-

-

-

Perry M. Waughtal10

39,050

*

-

-

37,594

*

50,000

*

Joseph Listengart11

4,198

*

-

-

-

-

140,106

*

Deborah A. Macdonald12

-

-

-

-

-

-

121,374

*

Richard T. Bradley13

-

-

-

-

-

-

71,314

*

Directors and Executive
Officers as
a group (12 persons)14

427,006

*

-

-

90,607

*

25,033,714

20.29%

Kinder Morgan, Inc.15

14,355,735

9.73%

5,313,400

100.00%

13,293,298

24.55%

-

-

Fayez Sarofim16

7,888,871

5.35%

-

-

-

-

-

-

Capital Group International,
Inc.17

-

-

-

-

4,970,550

9.18%

-

-

OppenheimerFunds, Inc.18

-

-

-

-

4,822,317

8.90%

-

-

Kayne Anderson Capital
Advisors, L.P.19

-

-

-

-

3,816,642

7.05%

-

-

____________

*Less than 1%.

1

Except as noted otherwise,
all units, our shares and Kinder Morgan, Inc. shares involve sole voting power and sole
investment power. For Kinder Morgan Management, LLC, see note (4). On January 18, 2005,
Kinder Morgan Management, LLC's board of directors initiated a rule requiring each
director to own a minimum of 10,000 common units, Kinder Morgan Management, LLC shares, or
a combination thereof. If a director does not already own the minimum number of required
securities, the director will have six years to acquire such securities.

2

As of January 31, 2005,
Kinder Morgan Energy Partners, L.P. had 147,555,658 common units issued and outstanding.

Represent the limited
liability company shares of Kinder Morgan Management, LLC. As of January 31, 2005, there
were 54,157,641 issued and outstanding Kinder Morgan Management, LLC shares, including two
voting shares owned by Kinder Morgan G.P., Inc. In all cases, Kinder Morgan Energy
Partners, L.P.'s i-units will be voted in proportion to the affirmative and negative
votes, abstentions and non-votes of owners of Kinder Morgan Management, LLC shares.
Through the provisions in Kinder Morgan Energy Partners, L.P.'s partnership agreement and
Kinder Morgan Management, LLC's limited liability company agreement, the number of
outstanding Kinder Morgan Management, LLC shares, including voting shares owned by Kinder
Morgan G.P., Inc., and the number of Kinder Morgan Energy Partners, L.P.'s i-units will at
all times be equal.

5

As of January 31, 2005,
Kinder Morgan, Inc. had a total of 123,378,197 shares of issued and outstanding voting
common stock, which excludes 11,076,901 shares held in treasury.

6

Includes (a) 7,879 common
units owned by Mr. Kinder's spouse, (b) 5,173 Kinder Morgan, Inc. shares held by Mr.
Kinder's spouse and (c) 250 Kinder Morgan, Inc. shares held by Mr. Kinder in a custodial
account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest
in these units and shares.

42

7

Includes options to
purchase 195,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31,
2005, and includes 112,500 shares of restricted Kinder Morgan, Inc. stock.

8

Includes 1,750 restricted
common units.

9

Includes options to
purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes
1,750 restricted common units.

10

Includes options to
purchase 10,000 common units exercisable within 60 days of January 31, 2005, and includes
1,750 restricted common units.

11

Includes options to
purchase 56,300 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005,
and includes 72,500 shares of restricted Kinder Morgan, Inc. stock.

12

Includes 102,500 shares of
restricted Kinder Morgan, Inc. stock.

13

Includes options to
purchase 20,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2005,
and includes 41,250 shares of restricted Kinder Morgan, Inc. stock.

14

Includes options to
purchase 24,000 common units and 433,300 Kinder Morgan, Inc. shares exercisable within 60
days of January 31, 2005, and includes 5,250 restricted common units and 467,500 shares of
restricted Kinder Morgan, Inc. stock.

15

Includes common units owned
by Kinder Morgan, Inc. and its consolidated subsidiaries, including 1,724,000 common units
owned by Kinder Morgan G.P., Inc.

16

As reported on the Schedule
13G/A filed February 11, 2005 by Fayez Sarofim & Co. and Fayez Sarofim. Mr. Sarofim
reports that in regard to Kinder Morgan Energy Partners, L.P.'s common units, he has sole
voting power over 2,300,000 common units, shared voting power over 4,242,612 common units,
sole disposition power over 2,300,000 common units and shared disposition power over
5,588,871 common units. Mr. Sarofim's address is 2907 Two Houston Center, Houston, Texas
77010.

17

As reported on the Schedule
13G/A filed February 14, 2005 by Capital Group International, Inc. and Capital Guardian
Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report
that in regard to Kinder Morgan Management, LLC shares, they have sole voting power over
3,913,560 shares, shared voting power over 0 shares, sole disposition power over 4,970,550
shares and shared disposition power over 0 shares. Capital Group International, Inc.'s and
Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles,
California 90025.

18

As reported on the Schedule
13G/A filed February 11, 2005 by OppenheimerFunds, Inc. and Oppenheimer Capital Income
Fund. OppenheimerFunds, Inc. reports that in regard to Kinder Morgan Management, LLC
shares, it has sole voting power over 0 shares, shared voting power over 0 shares, sole
disposition power over 0 shares and shared disposition power over 4,822,317 shares. Of
these 4,822,317 Kinder Morgan Management, LLC shares, Oppenheimer Capital Income Fund has
sole voting power over 3,232,500 shares, shared voting power over 0 shares, sole
disposition power over 0 shares and shared disposition power over 3,232,500 shares.
OppenheimerFunds, Inc.'s address is 225 Liberty Street, 11th Floor, New York,
New York 10281, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way,
Centennial, Colorado 80112.

19

As reported on the Schedule
13G filed February 11, 2005 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne.
Kayne Anderson Capital Advisors, L.P. reports that in regard to Kinder Morgan Management,
LLC shares, it has sole voting power over 0 shares, shared voting power over 3,815,712
shares, sole disposition power over 0 shares and shared disposition power over 3,815,712
shares. Mr. Anderson reports that in regard to Kinder Morgan Management, LLC shares, he
has sole voting power over 930 shares, shared voting power over 3,815,712 shares, sole
disposition power over 930 shares and shared disposition power over 3,815,712 shares.
Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne's address is 1800 Avenue of the
Stars, Second Floor, Los Angeles, California 90067.

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc.,
provides employees and Kinder Morgan Services LLC, our wholly owned subsidiary, provides
centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder
Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating
partnerships and subsidiaries (collectively, the "Group"). Employees of KMGP
Services Company, Inc. are assigned to work for one or more members of the Group. The
direct costs of all compensation, benefits expenses, employer taxes and other employer
expenses for these employees are allocated and charged by Kinder Morgan Services LLC to
the appropriate members of the Group, and the members of the Group reimburse for their
allocated shares of these direct costs. There is no profit or margin charged by Kinder
Morgan Services LLC to the members of the Group. The administrative support necessary to
implement these payroll and benefits services is provided by the human resource department
of Kinder Morgan, Inc., and the related administrative costs are allocated to members of
the Group in accordance with existing expense allocation procedures. The effect of these
arrangements is that each member of the Group bears the direct compensation and employee
benefits costs of its assigned or partially assigned employees, as the case may be, while
also bearing its allocable share of administrative costs. Pursuant to its limited
partnership agreement, Kinder Morgan Energy Partners, L.P. provides reimbursement for its
share of these administrative costs and such reimbursements will be accounted for as
described above. Additionally, Kinder Morgan Energy Partners, L.P. reimburses us with
respect to costs incurred or allocated to us in accordance with Kinder Morgan Energy
Partners, L.P.'s limited partnership agreement, the delegation of control agreement among
Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., us and others, and our
limited liability company agreement.

Our named executive officers and other employees that provide
management or services to both Kinder Morgan, Inc. and the Group are employed by Kinder
Morgan, Inc. Additionally, other Kinder Morgan, Inc. employees assist in the operation of
Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipeline assets. These Kinder Morgan,
Inc. employees' expenses are allocated without a profit component between Kinder Morgan,
Inc. and the appropriate members of the Group.

As of December 31, 2004, Kinder Morgan G.P., Inc. owned 1,724,000
common units, representing approximately 0.83% of Kinder Morgan Energy Partners, L.P.'s
outstanding limited partner units. Kinder Morgan Energy Partners, L.P.'s partnership
agreement requires that it distribute 100% of available cash, as defined in the
partnership agreement, to its partners within 45 days following the end of each calendar
quarter in accordance with their respective percentage interests. Available cash consists
generally of all of Kinder Morgan Energy Partners, L.P.'s cash receipts, including cash
received by its operating partnerships, less cash disbursements and net additions to
reserves (including any reserves required under debt instruments for future principal and
interest payments) and amounts payable to the former general partner of SFPP, L.P. in
respect of its remaining 0.5% interest in SFPP, L.P.

Kinder Morgan G.P., Inc. is granted discretion by Kinder Morgan Energy
Partners, L.P.'s partnership agreement, which discretion has been delegated to us, subject
to the approval of Kinder Morgan G.P., Inc. in certain cases, to establish, maintain and
adjust reserves for future operating expenses, debt service, maintenance capital
expenditures, rate refunds and distributions for the next four quarters. These reserves
are not restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When we determine Kinder Morgan Energy Partners, L.P.'s quarterly
distributions, we consider current and expected reserve needs along with current and
expected cash flows to identify the appropriate sustainable distribution level.

Kinder Morgan G.P., Inc. and owners of Kinder Morgan Energy Partners,
L.P.'s common units and Class B units receive distributions in cash, while we, the sole
owner of Kinder Morgan Energy Partners, L.P.'s i-units, receive distributions in
additional i-units. The cash equivalent of distributions of i-units is treated as if it
had actually been distributed for purposes of determining the distributions to Kinder
Morgan G.P., Inc. Kinder Morgan Energy Partners, L.P. does not distribute cash to i-unit
owners but retains the cash for use in its business.

Available cash is initially distributed 98% to Kinder Morgan Energy
Partners, L.P.'s limited partners and 2% to Kinder Morgan G.P., Inc. These distribution
percentages are modified to provide for incentive distributions to be paid to Kinder
Morgan G.P., Inc. in the event that quarterly distributions to unitholders exceed certain
specified targets.

Available cash for each quarter is distributed:



first, 98% to the owners of all classes of units pro rata and
2% to Kinder Morgan G.P., Inc. until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent

45

i-units for such quarter;



second, 85% of any available cash then remaining to the
owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. until the
owners of all classes of units have received a total of $0.17875 per unit in cash or
equivalent i-units for such quarter;



third, 75% of any available cash then remaining to the owners
of all classes of units pro rata and 25% to Kinder Morgan G.P., Inc. until the owners of
all classes of units have received a total of $0.23375 per unit in cash or equivalent
i-units for such quarter; and



fourth, 50% of any available cash then remaining to the
owners of all classes of units pro rata, to owners of common units and Class B units in
cash and to us, as the owner of i-units, in the equivalent number of i-units, and 50% to
Kinder Morgan G.P., Inc. in cash.

Incentive distributions are generally defined as all cash distributions
paid to Kinder Morgan G.P., Inc. that are in excess of 2% of the aggregate amount of cash
and i-units being distributed. Kinder Morgan G.P., Inc.'s declared incentive distributions
for the years ended December 31, 2004, 2003 and 2002 were $390.7 million, $322.8 million
and $267.4 million, respectively.

Kinder Morgan, Inc.

Kinder Morgan, Inc., through its subsidiary Kinder Morgan (Delaware),
Inc., remains the sole stockholder of Kinder Morgan G.P., Inc. At December 31, 2004,
Kinder Morgan, Inc. directly owned 8,838,095 common units and 5,313,400 Class B units,
indirectly owned 5,517,640 common units owned by its consolidated affiliates, including
Kinder Morgan G.P., Inc., and owned 15,135,460 of our shares, representing an indirect
ownership interest of 15,135,460 Kinder Morgan Energy Partners, L.P.'s i-units. Together,
these units represent approximately 16.8% of Kinder Morgan Energy Partners, L.P.'s
outstanding limited partner units. Including both its general and limited partner
interests in Kinder Morgan Energy Partners, L.P., at the 2004 distribution level, Kinder
Morgan, Inc. received approximately 51% of all quarterly distributions from Kinder Morgan
Energy Partners, L.P., of which approximately 41% is attributable to its general partner
interest and 10% is attributable to its limited partner interest. The actual level of
distributions Kinder Morgan, Inc. will receive in the future will vary with the level of
distributions to the limited partners determined in accordance with Kinder Morgan Energy
Partners, L.P.'s partnership agreement.

Kinder Morgan, Inc. or its subsidiaries operate and maintain for Kinder
Morgan Energy Partners, L.P. the assets comprising Kinder Morgan Energy Partners, L.P.'s
Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a
subsidiary of Kinder Morgan, Inc., operates Trailblazer Pipeline Company's assets under a
long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and
expenses related to Natural Gas Pipeline Company of America's operating and maintaining
the assets. Trailblazer Pipeline Company provides the funds for capital expenditures.
Natural Gas Pipeline Company of America does not profit from or suffer loss related to its
operation of Trailblazer Pipeline Company's assets.

Partners, L.P. Pursuant to the applicable underlying agreements, Kinder
Morgan Energy Partners, L.P. pays Kinder Morgan, Inc. either a fixed amount or actual
costs incurred as reimbursement for the corporate general and administrative expenses
incurred in connection with the operation of these assets. On January 1, 2003, Kinder
Morgan, Inc. began operating additional pipeline assets, including Kinder Morgan Energy
Partners, L.P.'s North System and Cypress Pipeline, which are part of Kinder Morgan Energy
Partners, L.P.'s Products Pipelines business segment. The amounts paid to Kinder Morgan,
Inc. for corporate general and administrative costs, including amounts related to
Trailblazer Pipeline Company, were$8.8 million of fixed costs and $13.1 million of
actual costs incurred for 2004, and $8.7 million of fixed costs and $10.8 million of
actual costs incurred for 2003. Kinder Morgan Energy Partners, L.P. estimates the total
reimbursement for corporate general and administrative costs to be paid to Kinder Morgan,
Inc. in respect of all pipeline assets operated by Kinder Morgan, Inc. and its
subsidiaries for Kinder Morgan Energy Partners, L.P. for 2005 will be approximately $24.7
million, which includes $5.5 million of fixed costs (adjusted for inflation) and $19.2
million of actual costs.

Kinder Morgan Energy Partners, L.P. believes the amounts paid to Kinder
Morgan, Inc. for the services they provided each year fairly reflect the value of the
services performed. However, due to the nature of the allocations, these reimbursements
may not have exactly matched the actual time and overhead spent. Kinder Morgan Energy
Partners, L.P. believes the fixed amounts that were agreed upon at the time the contracts
were entered into were reasonable estimates of the corporate general and administrative
expenses to be incurred by Kinder Morgan, Inc. and its subsidiaries in performing such
services. Kinder Morgan Energy Partners, L.P. also reimburses Kinder Morgan, Inc. and its
subsidiaries for operating and maintenance costs and capital expenditures incurred with
respect to these assets.

From time to time in the ordinary course of business, Kinder Morgan
Energy Partners, L.P. buys and sells pipeline and related services from Kinder Morgan,
Inc. and its subsidiaries. Such transactions are conducted in accordance with all
applicable laws and regulations and on an arms' length basis consistent with Kinder Morgan
Energy Partners, L.P.'s policies governing such transactions.

Generally, we make all decisions relating to the management and control
of Kinder Morgan Energy Partners, L.P.'s business. Kinder Morgan G.P., Inc. owns all of
our voting securities and is our sole managing member. Kinder Morgan, Inc., through its
wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common
stock of Kinder Morgan G.P., Inc. Certain conflicts of interest could arise as a result of
the relationships among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc.,
Kinder Morgan, Inc. and us. The directors and officers of Kinder Morgan, Inc. have
fiduciary duties to manage Kinder Morgan, Inc., including selection and management of its
investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders
of Kinder Morgan, Inc. In general, we have a fiduciary duty to manage Kinder Morgan Energy
Partners, L.P. in a manner beneficial to Kinder Morgan Energy Partners, L.P. unitholders.
The partnership agreements for Kinder

47

Morgan Energy Partners, L.P. and its operating partnerships contain
provisions that allow us to take into account the interests of parties in addition to
Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest, thereby limiting
our fiduciary duty to Kinder Morgan Energy Partners, L.P. unitholders, as well as
provisions that may restrict the remedies available to Kinder Morgan Energy Partners, L.P.
unitholders for actions taken that might, without such limitations, constitute breaches of
fiduciary duty.

The partnership agreements provide that in the absence of bad faith by
us, the resolution of a conflict by us will not be a breach of any duties. The duty of the
directors and officers of Kinder Morgan, Inc. to the shareholders of Kinder Morgan, Inc.
may, therefore, come into conflict with our duties and the duties of our directors and
officers to Kinder Morgan Energy Partners, L.P. unitholders. The Audit Committee of our
board of directors will, at our request, review (and is one of the means for resolving)
conflicts of interest that may arise between Kinder Morgan, Inc. or its subsidiaries, on
the one hand, and Kinder Morgan Energy Partners, L.P., on the other hand.

The following sets forth fees billed for the audit and other services
provided by PricewaterhouseCoopers LLP to us for the fiscal years ended December 31, 2004,
and December 31, 2003:

Year Ended December 31,

2004

2003

(In dollars)

Audit fees1

$ 171,000

$ 72,667

Total

$ 171,000

$ 72,667

==========

==========

1

Includes fees for audit of annual financial
statements, reviews of the related quarterly financial statements and reviews of documents
filed with the Securities and Exchange Commission.

All services rendered by PricewaterhouseCoopers LLP are permissible
under applicable laws and regulations, and are pre-approved by our audit committee.
Pursuant to the charter of our audit committee, the committee's primary purposes include
the following:

to pre-approve all audit and non-audit services, including
tax services, to be provided, consistent with all applicable laws, to us by our external
auditors; and



to establish the fees and other compensation to be paid to
our external auditors.

Furthermore, the audit committee will review the external auditors'
proposed audit scope and approach as well as the performance of the external auditors. It
also has direct responsibility for and sole authority to resolve any disagreements between
our management and our external auditors regarding financial reporting, will regularly
review with the external auditors any problems or difficulties the auditors encountered in
the course of their audit work, and will, at least annually, use its reasonable efforts to
obtain and review a report from the external auditors addressing the following (among
other items):



the auditors' internal quality-control procedures;



any material issues raised by the most recent internal
quality-control review, or peer review, of the external auditors;



the independence of the external auditors; and



the aggregate fees billed by our external auditors for each
of the previous two fiscal years.

Reference is made to the index of financial statements and
supplementary data under Item 8 in Part II.

2.

Financial Statement Schedules

The financial statements of Kinder Morgan Energy Partners, L.P., an
equity method investee of the Registrant, are incorporated herein by reference from pages
101 through 181 of Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for
the year ended December 31, 2004.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS

We have no valuation or qualifying accounts subject to disclosure in Schedule II.

3.

Exhibits

ExhibitNumber

Description

3.1

Form of Certificate of Formation of the
Company (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1
(Registration No. 333-55868) and incorporated by reference herein).

3.2

Second Amended and Restated Limited
Liability Company Agreement of the Company (filed as Exhibit 4.2 to the Company's
Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference
herein).

4.1

Form of certificate representing shares of
the Company (filed as Exhibit 4.3 to the Company's Registration Statement on Form 8-A/A
filed on July 24, 2002 and incorporated by reference herein).

4.2

Form of Purchase Provisions between the
Company and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated
Limited Liability Company Agreement filed as Exhibit 4.2 to the Company's Registration
Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).

4.3

Registration Rights Agreement dated May
18, 2001 among the Company, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc.
(Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31,
2002).

10.1

Form of Tax Indemnity Agreement between
the Company and Kinder Morgan, Inc. (filed as Exhibit 10.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein).

Resignation and Non-Compete Agreement,
dated as of July 21, 2004, between KMGP Services, Inc. and Michael C. Morgan (Exhibit 10.4
to Kinder Morgan Management, LLC's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2004).

21.1*

List of Subsidiaries.

23.1*

Consent of PricewaterhouseCoopers LLP.

31.1*

Certification of Chief Executive Officer
pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

Certification of Chief Financial Officer
pursuant to Rule13a-14(a)or15d-14(a) of
the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

32.1*

Certification of Chief Executive Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

32.2*

Certification of Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

KINDER
MORGAN MANAGEMENT, LLC
(Registrant)

By

/s/ C. Park Shaper

C. Park ShaperExecutive Vice President and Chief Financial Officer

Date: March 4, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the Registrant and
in the capacities set forth below and as of the date set forth above.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-11234
Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0380342
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
---------------
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Units New York Stock Exchange
Securities registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
Aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant, based on closing prices in the daily composite
list for transactions on the New York Stock Exchange on June 30, 2004 was
approximately $5,153,909,088. As of January 31, 2005, the registrant had
147,555,658 Common Units outstanding.
1
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KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I
Items 1 and 2. Business and Properties....................... 3
Overview...................................... 3
General Development of Business............... 3
History...................................... 4
Business Strategy............................ 4
Recent Developments.......................... 7
Financial Information about Segments.......... 10
Narrative Description of Business............. 10
Products Pipelines........................... 10
Natural Gas Pipelines........................ 22
CO2.......................................... 29
Terminals.................................... 32
Major Customers............................... 39
Regulation.................................... 39
Environmental Matters......................... 42
Risk Factors.................................. 45
Other......................................... 50
Financial Information about Geographic Areas.. 51
Available Information......................... 51
Item 3. Legal Proceedings.............................. 51
Item 4. Submission of Matters to a Vote of Security
Holders....................................... 51
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters and Issuer
Purchases of Equity Securities................ 52
Item 6. Selected Financial Data........................ 53
Item 7. Management's Discussion and Analysis of
Financial Condition and Results
of Operations................................. 55
Critical Accounting Policies and Estimates.... 55
Results of Operations......................... 57
Liquidity and Capital Resources............... 70
Recent Accounting Pronouncements.............. 79
Information Regarding Forward-Looking
Statements................................... 79
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk............................. 81
Energy Financial Instruments.................. 81
Interest Rate Risk............................ 82
Item 8. Financial Statements and Supplementary Data.... 83
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........ 83
Item 9A. Controls and Procedures........................ 83
Item 9B. Other Information.............................. 84
PART III
Item 10. Directors and Executive Officers of the
Registrant.................................... 85
Directors and Executive Officers of
our General Partner and the Delegate......... 85
Corporate Governance......................... 87
Section 16(a) Beneficial Ownership
Reporting Compliance........................ 88
Item 11. Executive Compensation......................... 88
Item 12. Security Ownership of Certain Beneficial
Owners and Management......................... 94
Item 13. Certain Relationships and Related
Transactions.................................. 96
Item 14. Principal Accounting Fees and Services......... 96
PART IV
Item 15. Exhibits and Financial Statement Schedules..... 98
Index to Financial Statements.................. 101
Signatures..................................................... 188
2
<PAGE>
PART I
Items 1 and 2. Business and Properties.
Overview
Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a
publicly traded limited partnership that was formed in August 1992. We are one
of the largest publicly-traded pipeline limited partnerships in the United
States in terms of market capitalization and we own the largest independent
refined petroleum products pipeline system in the United States in terms of
volumes delivered. Unless the context requires otherwise, references to "we,"
"us," "our," "KMP" or the "Partnership" are intended to mean Kinder Morgan
Energy Partners, L.P., our subsidiary operating limited partnerships and their
subsidiaries.
The address of our principal executive offices is 500 Dallas, Suite 1000,
Houston, Texas 77002, and our telephone number at this address is (713)
369-9000. Our common units trade on the New York Stock Exchange under the symbol
"KMP." You should read the following discussion and analysis in conjunction with
our consolidated financial statements included elsewhere in this report.
(a) General Development of Business
We focus on providing fee-based services to customers and creating value
for our unitholders primarily through the following activities:
o transporting, storing and processing refined petroleum products;
o transporting, storing and selling natural gas;
o producing, transporting and selling carbon dioxide for use in, and
selling crude oil produced from, enhanced oil recovery operations; and
o transloading, storing and delivering a wide variety of bulk, petroleum
and petrochemical products at terminal facilities located across the
United States.
Our operations are conducted through our subsidiary operating limited
partnerships and their subsidiaries. While we conduct these operations, we focus
on generally avoiding commodity price risks and maximizing the benefits of our
characterization as a partnership for federal income tax purposes. The portfolio
of businesses we own or operate are grouped into four reportable business
segments according to the services we provide and how our management makes
decisions about allocating resources and measuring financial performance. These
segments are as follows:
o Products Pipelines. Delivers gasoline, diesel fuel, jet fuel and
natural gas liquids to various markets through over 10,000 miles of
products pipelines and 60 associated terminals serving customers
across the United States;
o Natural Gas Pipelines. Transports, stores and sells natural gas over
approximately 14,000 miles of natural gas transmission pipelines and
gathering lines, plus natural gas gathering and storage facilities;
o CO2. Produces, transports through pipelines and markets carbon
dioxide, commonly called CO2, to oil fields that use CO2 to increase
production of oil, owns interests in and/or operates six oil fields in
West Texas, and owns and operates a crude oil pipeline system in West
Texas; and
o Terminals. Composed of approximately 75 owned or operated liquid and
bulk terminal facilities and more than 55 rail transloading and
materials handling facilities located throughout the United States.
3
<PAGE>
History
In February 1997, Kinder Morgan (Delaware), Inc., a Delaware corporation,
acquired all of the issued and outstanding stock of our general partner, changed
the name of our general partner to Kinder Morgan, G.P., Inc., and changed our
name to Kinder Morgan Energy Partners, L.P. Since that time, our operations have
experienced significant growth, and our net income has increased from $17.7
million for the year ended December 31, 1997, to $831.6 million for the year
ended December 31, 2004.
In October 1999, K N Energy, Inc., a Kansas corporation that provided
integrated energy services, acquired Kinder Morgan (Delaware), Inc. At the time
of the closing of this transaction, K N Energy, Inc. changed its name to Kinder
Morgan, Inc., referred to in this report as KMI. In connection with the
acquisition, Richard D. Kinder, Chairman and Chief Executive Officer of our
general partner and its delegate (see below), became the Chairman and Chief
Executive Officer of KMI. KMI trades on the New York Stock Exchange under the
symbol "KMI" and is one of the largest energy transportation and storage
companies in the United States, operating, either for itself or on our behalf,
more than 35,000 miles of natural gas and products pipelines and approximately
135 terminals. As of December 31, 2004, KMI and its consolidated subsidiaries
owned, through its general and limited partner interests, an approximate 18.5%
interest in us.
In addition to the distributions it receives from its limited and general
partner interests, KMI also receives an incentive distribution from us as a
result of its ownership of our general partner. This incentive distribution is
calculated in increments based on the amount by which quarterly distributions to
our unitholders exceed specified target levels as set forth in our partnership
agreement, reaching a maximum of 50% of distributions allocated to the general
partner for distributions above $0.23375 per limited partner unit per quarter.
Including both its general and limited partner interests in us, at the 2004
distribution level, KMI received approximately 51% of all quarterly
distributions from us, of which approximately 41% was attributable to its
general partner interest and 10% was attributable to its limited partner
interest. The actual level of distributions KMI will receive in the future will
vary with the level of distributions to our limited partners determined in
accordance with our partnership agreement.
In February 2001, Kinder Morgan Management, LLC, a Delaware limited
liability company referred to in this report as KMR, was formed. Our general
partner owns all of KMR's voting securities and, pursuant to a delegation of
control agreement, our general partner delegated to KMR, to the fullest extent
permitted under Delaware law and our partnership agreement, all of its power and
authority to manage and control our business and affairs, except that KMR cannot
take certain specified actions without the approval of our general partner.
Under the delegation of control agreement, KMR, as the delegate of our general
partner, manages and controls our business and affairs and the business and
affairs of our operating limited partnerships and their subsidiaries.
Furthermore, in accordance with its limited liability company agreement, KMR's
activities are limited to being a limited partner in, and managing and
controlling the business and affairs of us, our operating limited partnerships
and their subsidiaries.
In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares to the public in
an initial public offering. The shares trade on the New York Stock Exchange
under the symbol "KMR." KMR became a limited partner in us by using
substantially all of the net proceeds from that offering to purchase i-units
from us. The i-units are a separate class of limited partner interests in us and
are issued only to KMR. Under the terms of our partnership agreement, the
i-units are entitled to vote on all matters on which the common units are
entitled to vote. In general, our limited partner units, consisting of i-units,
common units and Class B units (the Class B units are similar to our common
units except that they are not eligible for trading on the New York Stock
Exchange), will vote together as a single class, with each i-unit, common unit,
and Class B unit having one vote. We pay our quarterly distributions from
operations and from interim capital transactions to KMR in additional i-units
rather than in cash. As of December 31, 2004, KMR, through its ownership of our
i-units, owned approximately 26.2% of all of our outstanding limited partner
units.
Business Strategy
The objective of our business strategy is to grow our portfolio of
businesses by:
o providing, for a fee, transportation, storage and handling services
which are core to the energy infrastructure of growing markets;
4
<PAGE>
o increasing utilization of our assets while controlling costs by:
o operating classic fixed-cost businesses with relatively little
variable costs; and
o improving productivity to drop top-line growth to the bottom
line;
o leveraging economies of scale from incremental acquisitions and
expansions principally by:
o reducing overhead; and
o eliminating duplicate costs in core operations; and
o maximizing the benefits of our financial structure, which allows us
to:
o minimize the taxation of net income, thereby increasing
distributions from our high cash flow businesses; and
o maintain a strong balance sheet, thereby allowing flexibility
when raising capital for acquisitions and/or expansions.
Primarily, our business model consists of a solid asset base designed and
operated to generate stable, fee-based income and distributable cash flow that
together provides overall long-term value to our unitholders. Generally, as
utilization of our pipelines and terminals increases, our fee-based revenues
increase. We do not face significant risks relating directly to short-term
movements in commodity prices for two principal reasons. First, we primarily
transport and/or handle products for a fee and are not engaged in significant
unmatched purchases and resales of commodity products. Second, in those areas of
our business, primarily oil production in our CO2 business segment, where we do
face exposure to fluctuations in commodity prices, we engage in a hedging
program to mitigate this exposure.
The business strategies of our four business segments are as follows:
o Products Pipelines. We plan to continue to expand our presence in the
growing refined petroleum products markets in the western and
southeastern United States through incremental pipeline expansions and
through strategic pipeline and terminal acquisitions that we believe
will enhance our ability to serve our customers while increasing
distributable cash flow. On systems serving relatively mature markets,
such as our North System, we intend to focus on increasing product
throughput by continuing to increase the range of products transported
and services offered while remaining a reliable, cost-effective
provider of transportation services;
o Natural Gas Pipelines. We intend to grow our Texas intrastate natural
gas transportation and storage businesses by identifying and serving
significant new customers with demand for capacity on our pipeline
systems and reducing volatility through long-term agreements. On our
Rocky Mountain natural gas pipeline systems, our goals are to continue
to operate our existing operations efficiently, to continue to meet
our customers' needs and to capitalize on expansion and growth
opportunities in moving natural gas out of the Rocky Mountain region.
Red Cedar Gas Gathering Company, our partnership with the Southern Ute
Indian Tribe, is pursuing additional gathering opportunities on tribal
lands. Overall, we will continue to explore expansion and storage
opportunities to increase utilization levels throughout our natural
gas pipeline operations;
o CO2. Our carbon dioxide sales and transportation business has two
primary strategies. First, we seek to increase the utilization of our
carbon dioxide supply and transportation assets by providing a full
range of supply, transportation and technical support services to
third party customers. As a service provider, our strategy is to offer
customers "one-stop shopping" for carbon dioxide supply,
transportation and technical support service. Second, we seek to
increase the economic benefits from our oil and gas production
activities by increasing oil field carbon dioxide flooding,
efficiently managing oil field operating expenses, and capturing
downstream value in assets which complement our oil field operations.
In our oil and gas
5
<PAGE>
production business, we plan to grow production from our interests in
oil fields located in the Permian Basin of West Texas by increasing
our use of carbon dioxide in enhanced oil recovery projects. We intend
to compete for new supply and transportation projects, both inside and
outside the Permian Basin, including the acquisition of attractive
carbon dioxide injection projects that would further increase the
demand for our carbon dioxide reserves and utilization of our carbon
dioxide supply and pipeline assets. Our management believes these
projects will arise as other oil producing basins mature and make the
transition from primary production to enhanced recovery methods; and
o Terminals. We are dedicated to growing our terminals segment through a
core strategy which includes dedicating capital to expand existing
facilities, maintaining a strong commitment to operational safety and
efficiency, and growing through strategic acquisitions. The bulk
terminals industry in the United States is highly fragmented, leading
to opportunities for us to make selective, accretive acquisitions. In
addition to efforts to expand and improve our existing terminals, we
plan to design, construct and operate new facilities for current and
prospective customers. Our management believes we can use newly
acquired or developed facilities to leverage our operational expertise
and customer relationships. In addition, we believe our experience and
expertise in managing and operating our liquids and bulk terminals
businesses in an integrated manner gives us an advantage in pursuing
acquisitions of terminals that handle both bulk and liquid materials.
To accomplish our strategy, we will continue to rely on the following
three-pronged approach:
o Cost Reductions. We continue to seek greater productivity and cost
savings by focusing on the efficiencies of our operations and the
related incurrence of associated operating, maintenance, and general
and administrative expenses. In addition, we have made reductions in
the operating, maintenance, and general and administrative expenses of
many of the businesses and assets that we have acquired. Generally,
these reductions in expense have been achieved by eliminating
duplicative functions that we and the acquired businesses each
maintained prior to their combination;
o Internal Growth. We intend to grow income from our current assets both
through increased utilization of existing assets, and through internal
expansion projects. We primarily operate classic fixed cost businesses
with relatively little variable costs. By controlling variable costs,
any increase in utilization of our pipelines and terminals generally
results in an increase in income. Increases in utilization are
principally driven by increases in demand for gasoline, jet fuel,
natural gas and other energy products and bulk materials that we
transport, store or handle. Increases in demand for these products are
typically driven by demographic growth in markets we serve, including
the rapidly growing western and southeastern United States. In
addition, we have undertaken a number of expansion projects that we
believe will increase revenues from existing operations; and
o Strategic Acquisitions. We regularly seek opportunities to make
additional strategic acquisitions, to expand existing businesses and
to enter into related businesses. We regularly consider and enter into
discussions regarding potential acquisitions, including those from KMI
or its affiliates, and are currently contemplating potential
acquisitions. While there are currently no unannounced purchase
agreements for the acquisition of any material business or assets,
such transactions can be effected quickly, may occur at any time and
may be significant in size relative to our existing assets or
operations. We anticipate financing acquisitions by borrowings under
our bank credit facility or by issuing commercial paper, and
subsequently reducing these short-term borrowings by issuing new
long-term debt securities, common units and/or i-units to KMR. For
more information on the costs and methods of financing for each of our
2004 acquisitions, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources - Capital Requirements for Recent Transactions" included
elsewhere in this report.
Achieving success in implementing our strategy will depend partly on the
following characteristics of our management's philosophy:
o Low cost asset operator and attention to detail. An important element
of our strategy to improve unitholder value is controlling costs
whenever possible. We believe that our overall cost and expense
infrastructure has been improved by numerous simplification and
transformation efforts. We continue to focus on improving employee and
process productivity in order to create a more efficient expense
structure while, at the same
6
<PAGE>
time, we focus on providing the highest level of expertise and
uncompromising service to our customers. We have recognized for years
the need to have an unwavering commitment to safety, and we employ
full-time safety professionals to provide training and awareness
through ongoing programs for our employees, especially those working
with hazardous materials at our pipeline and terminal facilities;
o Risk Management. We avoid businesses with direct commodity price
exposure wherever possible, and we hedge incidental commodity price
risk. In the normal course of business, we are exposed to risks
associated with changes in the market price of energy products;
however, we attempt to limit these risks by following established risk
management policies and procedures, including the use of energy
financial instruments, also known as derivatives. Our risk management
process also includes identifying the areas in our operations where
assets are at risk of loss and areas where exposures exist to
third-party liabilities. Our management strives to recognize and
insure against such risk; and
o Alignment of incentives. Whenever possible, we align the compensation
of our management and employees with the interests of our unitholders.
Under the Kinder Morgan Savings Plan, a defined contribution 401(k)
plan, all full-time employees of KMI and KMGP Services Company, Inc.
(the entities that employ all persons necessary for the operation of
our business) can contribute between 1% and 50% of base compensation,
on a pre-tax basis, into participant accounts. In addition to a
mandatory contribution equal to 4% of base compensation per year for
most plan participants, our general partner may make discretionary
contributions in years when specific performance objectives are met.
All employer contributions, including discretionary contributions, are
in the form of KMI stock that is immediately convertible into other
available investment vehicles at the employee's discretion.
Furthermore, KMI's ten most senior executives (excluding Mr. Kinder,
who receives $1 per year in salary and receives no bonus) have their
base salaries capped at $200,000 per year and are not eligible for
stock options, but instead are eligible to receive grants of KMI
restricted stock. Additionally, all employees, including the most
senior executives, are eligible for annual bonuses when KMI and we
meet annual earnings per share and distributions per unit targets.
Recent Developments
The following is a brief listing of significant developments since December
31, 2003. Additional information regarding most of these items may be found
elsewhere in this report.
o On February 9, 2004, we completed a public offering of an additional
5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We received net proceeds of
$237.8 million for the issuance of these common units and we used the
proceeds to reduce the borrowings under our commercial paper program;
o Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil
Corporation for an aggregate consideration of approximately $50.9
million, consisting of $48.2 million in cash and the assumption of
$2.7 million of liabilities. In addition, as part of the transaction,
ExxonMobil entered into a long-term contract to store refined
petroleum products at the terminals. As of our acquisition date, we
expected to invest an additional $1.2 million in the facilities in the
near-term following acquisition. The terminals are located in Collins,
Mississippi; Knoxville, Tennessee; Charlotte and Greensboro, North
Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the
terminals have a total storage capacity of approximately 3.2 million
barrels for gasoline, diesel fuel and jet fuel;
o On March 26, 2004, the Federal Energy Regulatory Commission issued an
order on the phase one initial decision that was issued on June 24,
2003 by an administrative law judge hearing a case on the rates
charged by our Pacific operations' interstate portion of its
pipelines. We believe the Energy Policy Act of 1992 "grandfathered"
most of our Pacific operations' interstate rates, deeming them lawful.
However, pursuant to rate challenges made by certain shippers, the
administrative law judge recommended that the FERC "ungrandfather" our
Pacific operations' interstate rates. The FERC's phase one order
reversed the initial decision by finding that our Pacific operations'
rates for its North and Oregon Lines should remain "grandfathered" and
amended the initial decision by finding that SFPP's West Line rates
(i) to Yuma and Tucson, Arizona and to our CALNEV Pipeline, as of
1995, and (ii) to Phoenix, Arizona, as of 1997, should
7
<PAGE>
no longer be "grandfathered" and are not just and reasonable. If these
rates are "ungrandfathered," they could be lowered prospectively and
complaining shippers could be entitled to reparations for prior
periods. Both SFPP and certain shippers have appealed the FERC's
decision to the United States Court of Appeals for the District of
Columbia;
o On June 1, 2004, we commenced service on our Kinder Morgan Interstate
Gas Transmission LLC's Cheyenne Market Center. This $28.4 million
project involved the construction of pipeline, compression and storage
facilities to accommodate an additional six billion cubic feet of
natural gas storage capacity, which has been fully subscribed under
10-year contracts. The Cheyenne Market Center offers firm natural gas
storage capabilities that allow for the receipt, storage and
subsequent re-delivery of natural gas supplies at applicable points
located in the vicinity of the Cheyenne Hub in Weld County, Colorado
and our Huntsman storage facility in Cheyenne County, Nebraska;
o On July 13, 2004, we announced that we had commenced service on our
135-mile natural gas pipeline segment which extends from an
intersection with our Kinder Morgan Texas Pipeline system just west of
Katy, Texas to the west side of Austin, Texas. The $30 million project
included the December 2003 acquisition of the pipeline, the subsequent
conversion of the pipeline from crude oil to natural gas service, and
the construction of a 5-mile pipeline lateral to serve a municipal
power plant located in Austin, Texas. The pipeline adds approximately
170 dekatherms per day of natural gas to the Austin market and is
supported by long-term contracts with local utilities;
o On August 18, 2004, we entered into a new five-year unsecured
revolving credit facility with a total commitment of $1.25 billion.
The new facility expires on August 18, 2009, and replaced our 364-day
and three-year facilities, which had total commitments of $1.05
billion. The five-year facility will result in benefits over our prior
credit facilities, including lower annual fees, reduced pricing and
rollover risk, and lower administrative costs. Our credit covenants
remained substantially unchanged as compared to the previous
facilities, with the only meaningful modification being the removal of
any net worth restriction. The facility primarily serves as a backup
to our commercial paper program, which had $416.9 million outstanding
as of December 31, 2004;
o Effective August 31, 2004, we acquired all of the partnership
interests in Kinder Morgan Wink Pipeline, L.P., formerly Kaston
Pipeline Company, L.P., from KPL Pipeline Company, LLC and RHC
Holdings, L.P. for an aggregate consideration of approximately $100.3
million, consisting of $89.9 million in cash and the assumption of
$10.4 million of liabilities. The acquisition included a 450-mile
crude oil pipeline system, consisting of four mainline sections,
numerous gathering systems and truck off-loading stations. The
mainline sections, all in the State of Texas, have a total capacity of
115,000 barrels of crude oil per day. As part of the transaction, we
entered into a long-term throughput agreement with Western Refining
Company, L.P. to transport crude oil into Western's 107,000 barrel per
day refinery in El Paso, Texas. As of the acquisition date, we
expected to invest approximately $11.0 million over the next five
years to upgrade the assets;
o On September 9, 2004, a non-binding, phase two initial decision was
issued by an administrative law judge hearing the FERC case on the
rates charged by our Pacific operations' interstate portion of its
pipelines. If affirmed by the FERC, the phase two initial decision
would establish the basis for prospective rates and the calculation of
reparations for complaining shippers with respect to our Pacific
operations' West Line and East Line. However, as with the phase one
initial decision, issued on June 24, 2003, the phase two initial
decision has no force or effect and must be fully reviewed by the
FERC, which may accept, reject or modify the decision. A FERC order on
phase two of the case is not expected before the third quarter of
2005. Furthermore, any such order may be subject to further FERC
review, review by the United States Court of Appeals for the District
of Columbia Circuit, or both;
o Effective October 1, 2004, we acquired an additional undivided 5%
interest in the Cochin Pipeline System from a subsidiary of
ConocoPhillips Corporation for approximately $10.9 million. We record
our 49.8% proportionate share of the results of operations of the
Cochin Pipeline System as part of our Products Pipelines business
segment;
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o Effective October 6, 2004, we acquired Kinder Morgan River Terminals
LLC, formerly Global Materials Services LLC, from Mid-South Terminal
Company, L.P. for an aggregate consideration of approximately $89.6
million, consisting of $31.8 million in cash and $57.8 million of
assumed liabilities. Kinder Morgan River Terminals LLC operates a
network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network
provides loading, storage and unloading points for various bulk
commodity imports and exports. As of the acquisition date, we expected
to invest an additional $9.4 million over the next two years to expand
and upgrade the terminals, which are located in 11 Mid-Continent
states;
o On October 13, 2004, we announced that Shell Trading (U.S.) Company
had assumed ownership of the processing rights at our transmix
facilities located in Richmond, Virginia; Indianola, Pennsylvania; and
Wood River, Illinois. In a transaction that closed on September 30,
2004, Shell Trading purchased the eastern transmix trading business
formerly owned by Duke Energy Merchants LLC, which included a transmix
processing agreement with us effective through March 16, 2011;
o Effective November 1, 2004, we acquired all of the partnership
interests in TransColorado Gas Transmission Company from two
wholly-owned subsidiaries of KMI. TransColorado Gas Transmission
Company is a Colorado general partnership and, at the date of
acquisition, owned assets of approximately $284.5 million. As
consideration for TransColorado, we paid to KMI $211.2 million in cash
and assumed liabilities of approximately $9.3 million. In addition, we
issued 1,400,000 common units having a market value of approximately
$64 million to KMI. TransColorado owns a 300-mile interstate natural
gas pipeline that originates in the Piceance Basin of western Colorado
and extends to the Blanco Hub in northwest New Mexico, providing a
strategic link to the southwestern United States and other key
markets;
o Effective November 5, 2004, we acquired ownership interests in nine
refined petroleum products terminals in the southeastern United States
from Charter Terminal Company and Charter-Triad Terminals, LLC for an
aggregate consideration of approximately $75.2 million, consisting of
$72.4 million in cash and $2.8 million of assumed liabilities. Three
terminals are located in Selma, North Carolina, and the remaining
facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta,
South Carolina. We fully own seven of the terminals and jointly own
the remaining two. The nine facilities have a combined 3.2 million
barrels of storage. As of the acquisition date, we expected to invest
an additional $2 million over the next two years to upgrade the
facilities. All of the terminals are connected to products pipelines
owned by either Plantation Pipe Line Company or Colonial Pipeline
Company, and the acquisition will increase our southeast terminal
storage capacity 76% (to 7.7 million barrels) and terminal throughput
capacity 62% (to over 340,000 barrels per day);
o On November 10, 2004, we completed a public offering of 5,500,000 of
our common units at a price of $46.00 per unit, less commissions and
underwriting expenses. On December 8, 2004, we issued an additional
575,000 units upon the exercise by the underwriters of an
over-allotment option. We received net proceeds of $268.3 million for
the issuance of these 6,075,000 common units. At approximately the
same time as our November public offering, KMR issued 1,300,000 of its
shares at a price of $41.29 per share, less closing fees and
commissions. The net proceeds from the offering were used by KMR to
buy additional i-units from us, and we received net proceeds of $52.6
million for the issuance of 1,300,000 i-units. We used the proceeds
from each of these three issuances to reduce the borrowings under our
commercial paper program;
o On November 12, 2004, we closed a public offering of $500 million in
principal amount of 5.125% senior notes due November 15, 2014. The
proceeds to us from the issuance of the notes, after underwriting
discounts and commissions, were approximately $496.3 million, which we
used to reduce commercial paper debt;
o Effective December 1, 2004, we acquired substantially all of the
assets used to operate the major port distribution facility located at
the Fairless Industrial Park in Bucks County, Pennsylvania. The
aggregate cost of the acquisition was approximately $7.5 million,
consisting of $7.2 million in cash and $0.3 million in assumed
liabilities. The bulk terminal facility is located on the Delaware
River and is the largest port on the East Coast for the handling of
semi-finished steel slabs, which are used as feedstock by domestic
steel mills. The facility, referred to as our Kinder Morgan Fairless
Hills Terminal, was purchased from Novolog Bucks
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County, Inc. The port operations at Fairless Hills also include the
handling of other types of steel and specialized cargo that caters to
the construction industry and service centers that use steel sheet and
plate. As of the acquisition date, we expected to invest an additional
$8.3 million in the facility;
o On December 8, 2004, we announced that we expect to declare cash
distributions of $3.13 per unit for 2005, a 9% increase over our cash
distributions of $2.87 per unit for 2004. This expectation includes
contributions from assets owned by us as of the announcement date and
does not include any projected benefits from unidentified
acquisitions;
o On December 15, 2004, we announced the start of service on our new $95
million, 70-mile, 20-inch replacement common carrier refined petroleum
products pipeline between Concord and Sacramento, California. This
project included replacing an existing 14-inch diameter refined
products pipeline with a new 20-inch diameter line and rerouting
portions of the pipeline away from environmentally sensitive areas and
residential neighborhoods. The capital expansion project significantly
increases the capacity on the pipeline and provides the necessary
infrastructure to help meet the region's growing demand for gasoline,
diesel and jet fuel. Capacity on the new pipeline is approximately
167,000 barrels per day, and with additional pumping capability,
maximum capacity could increase to over 200,000 barrels per day;
o During 2004, we spent $747.3 million for additions to our property,
plant and equipment, including both expansion ($628.0 million) and
maintenance projects ($119.3 million). Our capital expenditures
included the following:
o $302.9 million in our CO2 segment, mostly related to additional
infrastructure, including wells, injection and compression
facilities, to support the expanding carbon dioxide flooding
operations at the SACROC and Yates oil field units in West Texas;
o $213.8 million in our Products Pipelines segment, mostly related
to expansion work on our Pacific operations' Concord to
Sacramento, California products pipeline, the expansion of our
Pacific operations' East Line products pipeline, described above,
and to a storage and expansion project at our combined Carson/Los
Angeles Harbor terminal system in the State of California;
o $124.2 million in our Terminals segment, largely related to
expanding the petroleum products storage capacity at our liquid
terminal facility located in Carteret, New Jersey and the
construction of a cement facility at our Dakota bulk terminal
located in St. Paul, Minnesota, as well as other smaller
projects; and
o $106.4 million in our Natural Gas Pipelines segment, mostly
related to completing the construction and start up of our
Cheyenne Market Center and our Katy to Austin, Texas intrastate
natural gas pipeline project, both described above; and
o On February 24, 2005, we announced that we had received the necessary
permits and approvals from the city of Carson, California, to
construct new storage tanks as part of a major expansion of our West
Coast petroleum products storage and transfer terminal located in
Carson, California. The almost $40 million investment includes the
addition of ten new tanks that will increase storage capacity at the
facility by 800,000 barrels (16%) and help meet Southern California's
growing demand for petroleum products.
(b) Financial Information about Segments
For financial information on our four reportable business segments, see
Note 15 to our consolidated financial statements.
(c) Narrative Description of Business
Products Pipelines
Our Products Pipelines segment consists of refined petroleum products and
natural gas liquids pipelines, related terminals and transmix processing
facilities, including:
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o our Pacific operations, which include interstate common carrier
pipelines regulated by the Federal Energy Regulatory Commission,
intrastate pipelines in California regulated by the California Public
Utilities Commission and certain non rate-regulated operations and
terminal facilities. Specifically, our Pacific operations include:
o our SFPP, L.P. operations, comprised of approximately 2,500 miles
of pipelines that transport refined petroleum products to some of
the fastest growing population centers in the United States,
including Southern California; the San Francisco Bay Area; Las
Vegas, Nevada (through our CALNEV Pipeline) and Phoenix and
Tucson, Arizona, and 13 truck-loading terminals with an aggregate
usable tankage capacity of approximately nine million barrels;
o our CALNEV Pipeline operations, comprised of approximately
550-miles of pipelines that transport refined petroleum products
from Colton, California to the growing Las Vegas, Nevada market,
McCarran International Airport in Las Vegas, Nevada, and refined
petroleum products terminals located in Barstow, California and
Las Vegas, Nevada; and
o our West Coast terminals operations, which are comprised of six
terminal facilities on the West Coast that transload and store
refined petroleum products;
o our Central Florida Pipeline, two pipelines that total 195-miles and
transport refined petroleum products from Tampa to the Orlando,
Florida market and two refined petroleum products terminals at Tampa
and Orlando, Florida;
o our North System, a 1,600-mile pipeline system that transports natural
gas liquids in both directions between south central Kansas and the
Chicago area and various intermediate points, including eight
terminals, and our 50% interest in the Heartland Pipeline Company,
which ships refined petroleum products in the Midwest;
o our 51% interest in Plantation Pipe Line Company, which owns the
3,100-mile Plantation pipeline system that transports refined
petroleum products throughout the southeastern United States, serving
major metropolitan areas including Birmingham, Alabama; Atlanta,
Georgia; Charlotte, North Carolina; and the Washington, D.C. area;
o our Kinder Morgan Southeast Terminals LLC, comprised of 23 refined
petroleum products terminals acquired between December 2003 and
November 2004;
o our 49.8% interest in the Cochin Pipeline system, a 1,900-mile
pipeline transporting natural gas liquids and traversing Canada and
the United States from Fort Saskatchewan, Alberta to Sarnia, Ontario,
including five terminals;
o our Cypress Pipeline, a 104-mile pipeline transporting natural gas
liquids from Mont Belvieu, Texas to a major petrochemical producer in
Lake Charles, Louisiana; and
o our Transmix operations, which include the processing of petroleum
pipeline transmix (a blend of dissimilar refined petroleum products
that have become co-mingled in the pipeline transportation process)
through transmix processing plants in Colton, California; Richmond,
Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and Wood
River, Illinois.
Pacific Operations
Our Pacific operations' pipelines are split into a South Region and a North
Region. Combined, the two regions consist of seven pipeline segments that serve
six western states with approximately 3,100 miles of refined petroleum products
pipeline and related terminal facilities.
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Refined petroleum products and related uses are:
Product Use
--------- --------------------------------
Gasoline Transportation
Diesel fuel Transportation (auto, rail, marine),
agricultural, industrial and commercial
Jet fuel Commercial and military air transportation
Our Pacific operations transport over 1.1 million barrels per day of
refined petroleum products, providing pipeline service to approximately 39
customer-owned terminals, nine commercial airports and 15 military bases. For
2004, the three main product types transported were gasoline (62%), diesel fuel
(22%) and jet fuel (16%). Our Pacific operations also include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV).
Our Pacific operations provide refined petroleum products to some of the
fastest growing population centers in the United States, including California;
Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. Pipeline
transportation of gasoline and jet fuel generally has a direct correlation with
demographic patterns. We believe that the population growth associated with the
markets served by our Pacific operations will continue in the foreseeable
future.
South Region. Our Pacific operations' South Region consists of four
pipeline segments:
o West Line;
o East Line;
o San Diego Line; and
o CALNEV Line.
The West Line consists of approximately 670 miles of primary pipeline and
currently transports products for 37 shippers from six refineries and three
pipeline terminals in the Los Angeles Basin to Phoenix and Tucson, Arizona and
various intermediate commercial and military delivery points. Product for the
West Line can also come from foreign and domestic sources through the Los
Angeles and Long Beach port complexes and the three pipeline terminals. A
significant portion of West Line volumes is transported to Colton, California
for local distribution and for delivery to our CALNEV Pipeline. The West Line
serves our terminals located in Colton and Imperial, California as well as in
Phoenix and Tucson, Arizona.
The East Line is comprised of two parallel 8-inch diameter and 12-inch
diameter pipelines originating in El Paso, Texas and continuing approximately
300 miles west to our Tucson terminal and one line continuing northwest
approximately 130 miles from Tucson to Phoenix. All products received by the
East Line at El Paso come from a refinery in El Paso or are delivered through
connections with non-affiliated pipelines from refineries in Texas and New
Mexico. The East Line serves our terminals located in Phoenix and Tucson as well
as various intermediate commercial and military delivery points. We have
embarked on a major expansion of this pipeline system. The expansion consists of
replacing 160 miles of 8-inch diameter pipe between El Paso and Tucson and 84
miles of 8-inch diameter pipe between Tucson and Phoenix, with 16-inch and
12-inch diameter pipe, respectively. The project also includes the construction
of a major origin pump station. The project is estimated to cost $210 million
and is scheduled to be completed in the first quarter of 2006.
The San Diego Line is a 135-mile pipeline serving major population areas in
Orange County (immediately south of Los Angeles) and San Diego. The same
refineries and terminals that supply the West Line also supply the San Diego
Line. The San Diego Line serves our terminals at Orange and Mission Valley as
well as shipper terminals in San Diego and San Diego Airport through a
non-affiliated connecting pipeline.
The CALNEV Line consists of two parallel 248-mile, 14-inch and 8-inch
diameter pipelines from our facilities at Colton, California to Las Vegas,
Nevada. It also includes approximately 55 miles of pipeline serving Edwards Air
Force Base. CALNEV originates at Colton, California and serves two CALNEV
terminals at Barstow, California and Las Vegas, Nevada. The CALNEV Pipeline also
serves McCarran International Airport, Edwards Air Force
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Base and Nellis Air Force Base, as well as certain smaller delivery points,
including the Burlington Northern Santa Fe and Union Pacific railroad yards.
North Region. Our Pacific operations' North Region consists of three
pipeline segments:
o the North Line;
o the Bakersfield Line; and
o the Oregon Line.
The North Line consists of approximately 820 miles of trunk pipeline in
five segments originating in Richmond and Concord, California. This line serves
our terminals located in Brisbane, Sacramento, Chico, Fresno and San Jose,
California, and Reno, Nevada. The products delivered through the North Line come
from refineries in the San Francisco Bay Area and from various pipeline and
marine terminals that deliver products from foreign and domestic ports.
On December 15, 2004, we announced the start of service on our new $95
million, 70-mile, 20-inch replacement common carrier pipeline between Concord
and Sacramento, California. The project included replacing the existing 14-inch
diameter refined products pipeline with a new 20-inch diameter line and
rerouting portions of the pipeline away from environmentally sensitive areas and
residential neighborhoods. The capital expansion project increases the capacity
on the pipeline from 119,000 barrels per day to 167,000 barrels per day, and
with additional pumping capability, maximum capacity could increase to 200,000
barrels per day.
The Bakersfield Line is a 100-mile, 8-inch diameter pipeline serving
Fresno, California. The Oregon Line is a 114-mile pipeline serving 13 shippers.
Our Oregon Line receives products from marine terminals in Portland, Oregon and
from Olympic Pipeline. Olympic Pipeline is a non-affiliated pipeline that
transports products from the Puget Sound, Washington area to Portland. From its
origination point in Portland, the Oregon Line extends south and serves our
terminal located in Eugene, Oregon.
West Coast Terminals. These terminals are operated as part of our Pacific
operations and include:
o the Carson Terminal;
o the Los Angeles Harbor Terminal;
o the Richmond Terminal;
o the Linnton and Willbridge Terminals; and
o the Harbor Island Terminal.
The West Coast terminals are fee-based terminals. They are located in
several strategic locations along the west coast of the United States and have a
combined total capacity of nearly eight million barrels of storage for both
petroleum products and chemicals.
The Carson terminal and the connected Los Angeles Harbor terminal are
strategically located near the many refineries in the Los Angeles Basin. The
combined Carson/LA Harbor system is connected to numerous other pipelines and
facilities throughout the Los Angeles area, which gives the system significant
flexibility and allows customers to quickly respond to market conditions.
Storage at the Carson facility is primarily arranged via term contracts with
customers, ranging from one to five years. Term contracts represent 52% of total
revenues at the facility.
The Richmond terminal is located in the San Francisco Bay Area. The
facility serves as a storage and distribution center for chemicals, lubricants
and paraffin waxes. It is also the principal location in northern California
through which tropical oils are imported for further processing, and from which
United States' produced
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vegetable oils are exported to consumers in the Far East.
The Linnton and Willbridge terminals are located in Portland, Oregon. These
facilities handle petroleum products for distribution to both local and regional
markets. Refined products are received by pipeline, marine vessel, barge, and
rail car for distribution to local markets by truck; to southern Oregon via our
Oregon Line; to Portland International Airport via a non-affiliated pipeline;
and to eastern Washington and Oregon by barge.
The Harbor Island terminal is located in Seattle, Washington. The facility
is supplied via pipeline and barge from northern Washington-state refineries,
allowing customers to distribute fuels economically to the greater Seattle-area
market by truck. The terminal is the largest marine fuel oil storage facility in
Puget Sound and also has a multi-component, in-line blending system for
providing customized bunker fuels to the marine industry.
Truck-Loading Terminals. Our Pacific operations include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage
capacity of approximately ten million barrels. The truck terminals are located
at most destination points on each of our Pacific operations' pipelines as well
as some intermediate points along each pipeline. The simultaneous truck-loading
capacity of each terminal ranges from two to 12 trucks. We provide the following
services at these terminals:
o short-term product storage;
o truck-loading;
o vapor handling;
o deposit control additive injection;
o dye injection;
o oxygenate blending; and
o quality control.
The capacity of terminaling facilities varies throughout our Pacific
operations. We charge a separate fee (in addition to pipeline tariffs) for these
additional terminaling services. These fees are not regulated except for the
fees at our CALNEV terminals. At certain locations, we make product deliveries
to facilities owned by shippers or independent terminal operators.
Markets. Currently our Pacific operations' pipeline system serves
approximately 75 shippers in the refined products market, with the largest
customers consisting of:
o major petroleum companies;
o independent refiners;
o the United States military; and
o independent marketers and distributors of refined petroleum products.
A substantial portion of the product volume transported is gasoline. Demand
for gasoline depends on such factors as prevailing economic conditions,
vehicular use patterns and demographic changes in the markets served. If current
trends continue, we expect the majority of our Pacific operations' markets to
maintain growth rates that will exceed the national average for the foreseeable
future.
Currently, the California gasoline market is approximately 970,000 barrels
per day. The Arizona gasoline market is served primarily by us at a market
demand of approximately 121,000 barrels per day. Nevada's gasoline market is
approximately 50,000 barrels per day and Oregon's is approximately 96,000
barrels per day. The diesel
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and jet fuel market is approximately 560,000 barrels per day in California,
73,000 barrels per day in Arizona, 40,000 barrels per day in Nevada and 63,000
barrels per day in Oregon. We transport over 1.1 million barrels of petroleum
products per day in these states.
The volume of products transported is directly affected by the level of
end-user demand for such products in the geographic regions served. Certain
product volumes can experience seasonal variations and, consequently, overall
volumes may be lower during the first and fourth quarters of each year.
California mandated the elimination of MTBE (methyl tertiary-butyl ether)
from gasoline by January 1, 2004. MTBE-blended gasoline has been replaced by
ethanol-blended gasoline. Since ethanol cannot be shipped by pipeline, we are
realizing a reduction in gasoline volumes delivered in California; however, our
overall revenues were not adversely impacted as our terminals receive a fee to
blend ethanol.
Supply. The majority of refined products supplied to our Pacific
operations' pipeline system come from the major refining centers around Los
Angeles, San Francisco and Puget Sound, as well as waterborne terminals located
near these refining centers.
Competition. The most significant competitors of our Pacific operations'
pipeline system are proprietary pipelines owned and operated by major oil
companies in the area where our pipeline system delivers products as well as
refineries with related trucking arrangements within our market areas. We
believe that high capital costs, tariff regulation and environmental permitting
considerations make it unlikely that a competing pipeline system comparable in
size and scope to our Pacific operations will be built in the foreseeable
future. However, the possibility of pipelines being constructed or expanded to
serve specific markets is a continuing competitive factor.
The use of trucks for product distribution from either shipper-owned
proprietary terminals or from their refining centers continues to compete for
short haul movements by pipeline. The mandated elimination of MTBE and required
substitution of ethanol in California gasoline has resulted in at least a
temporary increase in trucking distribution from shipper owned terminals. We
cannot predict with any certainty whether the use of short haul trucking will
decrease or increase in the future.
Longhorn Partners Pipeline is a joint venture pipeline project that began
transporting refined products from refineries on the Gulf Coast to El Paso and
other destinations in Texas in late 2004. Increased product supply in the El
Paso area could result in some shift of volumes transported into Arizona from
our West Line to our East Line. Increased movements into the Arizona market from
El Paso would currently displace higher tariff volumes supplied from Los Angeles
on our West Line. However, our East Line is currently running at full capacity
and we have plans to increase East Line capacity to meet market demand. The
planned capacity increase will require significant investment which should,
under the FERC cost of service methodology, result in a more balanced tariff
between our East and West Lines. Such shift of supply sourcing has not had, and
is not expected to have, a material effect on our operating results.
Terminals owned by our Pacific operations also compete with terminals owned
by our shippers and by third party terminal operators in numerous locations.
Competing terminals are located in Reno, Sacramento, San Jose, Stockton, Colton,
Orange County, Mission Valley, and San Diego, California and Phoenix and Tucson,
Arizona and Las Vegas, Nevada. Short haul trucking from the refinery centers is
also a competitive factor to close-in terminals.
Competitors of our Carson terminal in the refined products market include
Shell Oil Products U.S. and BP (formerly Arco Terminal Services Company). In the
crude/black oil market, competitors include Pacific Energy, Wilmington Liquid
Bulk Terminals (Vopak) and BP. Competition to our Richmond terminal's chemical
business comes primarily from IMTT. Competitors to our Linnton and Willbridge
terminals include ST Services, ChevronTexaco and Shell Oil Products U.S. Our
Harbor Island terminal competes primarily with nearby terminals owned by Shell
Oil Products U.S. and ConocoPhillips.
Central Florida Pipeline
We own and operate a liquids terminal in Tampa, Florida, a liquids terminal
in Taft, Florida (near Orlando, Florida) and an intrastate common carrier
pipeline system that serves customers' product storage and transportation
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needs in Central Florida. The Tampa terminal contains 31 above-ground storage
tanks consisting of approximately 1.4 million barrels of storage capacity and is
connected to two ship dock facilities in the Port of Tampa that unload refined
products from barges and ocean-going vessels into the terminal. The facility
also has a truck rack that can load in excess of 200 trucks per day and a
railroad terminal. The Tampa terminal provides storage for gasoline, diesel fuel
and jet fuel for further movement into either trucks through five truck-loading
racks or into the Central Florida pipeline system. The Tampa terminal also
provides storage for chemicals, predominantly used to treat citrus crops,
delivered to the terminal by vessel or rail car and loaded onto trucks through
five truck-loading racks. The Taft terminal contains 22 above-ground storage
tanks consisting of approximately 670,000 barrels of storage capacity, providing
storage for gasoline and diesel fuel for further movement into trucks through 11
truck-loading racks.
The Central Florida pipeline system consists of a 110-mile, 16-inch
diameter pipeline that transports gasoline and an 85-mile, 10-inch diameter
pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an
intermediate delivery point on the 10-inch pipeline at Intercession City,
Florida. In addition to being connected to our Tampa terminal, the pipeline
system is connected to terminals owned and operated by TransMontaigne, Citgo,
BP, and Marathon Ashland Petroleum. The control room for the pipeline is located
at the Tampa terminal. The 10-inch diameter pipeline is connected to our Taft
terminal and is also the sole pipeline supplying jet fuel to the Orlando
International Airport in Orlando, Florida. In 2004, the pipeline transported
approximately 103,000 barrels per day of refined products, with the product mix
being approximately 68% gasoline, 14% diesel fuel, and 18% jet fuel.
Markets. The estimated total refined petroleum product demand in the State
of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 545,000 barrels per day. The
total refined petroleum products demand for the Central Florida region of the
state, which includes the Tampa and Orlando markets, is estimated to be
approximately 350,000 barrels per day, or 44% of the consumption of refined
products in the state. Our market share is approximately 140,000 barrels per
day, or 40% of the Central Florida market. The balance of the market is supplied
primarily by trucking firms and marine transportation firms. Most of the jet
fuel used at Orlando International Airport is moved through our Tampa terminal
and the Central Florida pipeline system. The market in Central Florida is
seasonal, with demand peaks in March and April during spring break and again in
the summer vacation season, and is also heavily influenced by tourism, with
Disney World and other amusement parks located in Orlando.
Supply. The vast majority of refined petroleum products consumed in Florida
is supplied via marine vessels from major refining centers in the Gulf Coast of
Louisiana and Mississippi and refineries in the Caribbean basin. A lesser amount
of refined products is being supplied by refineries in Alabama and by Texas Gulf
Coast refineries via marine vessels and through pipeline networks that extend to
Bainbridge, Georgia. The supply into Florida is generally transported by
ocean-going vessels to the larger metropolitan ports, such as Tampa, Port
Everglades near Miami, and Jacksonville. Individual markets are then supplied
from terminals at these ports and other smaller ports, predominately by trucks,
except the Central Florida region, which is served by a combination of trucks
and pipelines.
Competition. With respect to the terminal operations at Tampa, the most
significant competitors are proprietary terminals owned and operated by major
oil companies, such as Marathon Ashland Petroleum, BP and Citgo, located along
the Port of Tampa, and the ChevronTexaco and Motiva terminals in Port Tampa.
These terminals generally support the storage requirements of their parent or
affiliated companies' refining and marketing operations and provide a mechanism
for an oil company to enter into exchange contracts with third parties to serve
its storage needs in markets where the oil company may not have terminal assets.
Due to the high capital costs of tank construction in Tampa and state
environmental regulation of terminal operations, we believe it is unlikely that
new competing terminals will be constructed in the foreseeable future.
With respect to the Central Florida pipeline system, the most significant
competitors are trucking firms and marine transportation firms. Trucking
transportation is more competitive in serving markets close to the marine
terminals on the east and west coasts of Florida. We are utilizing tariff
incentives to attract volumes to the pipeline that might otherwise enter the
Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral.
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Federal regulation of marine vessels, including the requirement, under the
Jones Act, that United States-flagged vessels contain double-hulls, is a
significant factor in reducing the fleet of vessels available to transport
refined petroleum products. Marine vessel owners are phasing in the requirement
based on the age of the vessel and some older vessels are being redeployed into
use in other jurisdictions rather than being retrofitted with a double-hull for
use in the United States. We believe it is unlikely that a new pipeline system
comparable in size and scope to our Central Florida Pipeline operations will be
constructed, due to the high cost of pipeline construction and environmental and
right-of-way permitting in Florida. However, the possibility of such a pipeline
being built is a continuing competitive factor.
North System
Our North System is an approximate 1,600-mile interstate common carrier
pipeline system used to deliver natural gas liquids and refined petroleum
products. Additionally, we include our 50% ownership interest in Heartland
Pipeline Company as part of our North System operations. ConocoPhillips owns the
remaining 50% of Heartland Pipeline Company.
Natural gas liquids are typically extracted from natural gas in liquid form
under low temperature and high pressure conditions. Natural gas liquids products
and related uses are as follows:
Product Use
----------- -----------------------------------
Propane Residential heating, industrial and agricultural
uses, petrochemical feedstock
Isobutane Further processing
Natural gasoline Further processing or blending into gasoline
motor fuel
Ethane/Propane Mix Feedstock for petrochemical plants or peak-shaving
facilities
Normal butane Feedstock for petrochemical plants or blending
into gasoline motor fuel
Our North System extends from south central Kansas to the Chicago area.
South central Kansas is a major hub for producing, gathering, storing,
fractionating and transporting natural gas liquids. Our North System's primary
pipelines are comprised of approximately 1,400 miles of 8-inch and 10-inch
diameter pipelines and include:
o two pipelines that originate at Bushton, Kansas and continue to a
major storage and terminal area in Des Moines, Iowa;
o a third pipeline, that extends from Bushton to the Kansas City,
Missouri area; and
o a fourth pipeline that extends from Des Moines to the Chicago area.
Through interconnections with other major liquids pipelines, our North
System's pipeline system connects mid-continent producing areas to markets in
the Midwest and eastern United States. We also have defined sole carrier rights
to use capacity on an extensive pipeline system owned by Magellan Midstream
Partners, L.P. that interconnects with our North System. This capacity lease
agreement, which requires us to pay approximately $2.2 million per year, is in
place until February 2013 and contains a five-year renewal option. In addition
to our capacity lease agreement with Magellan, we also have a reversal agreement
with Magellan to help provide for the transport of summer-time surplus butanes
from Chicago area refineries to storage facilities at Bushton. We have an annual
minimum joint tariff commitment of $0.6 million to Magellan for this agreement.
Our North System has approximately 5.6 million barrels of storage capacity,
which includes caverns, steel tanks, pipeline line-fill and leased storage
capacity. This storage capacity provides operating efficiencies and flexibility
in meeting seasonal demands of shippers and provides propane storage for our
truck-loading terminals.
The Heartland pipeline system was completed in 1990 and is owned by the
Heartland Pipeline Company. We own a 50% equity interest in Heartland. The
pipeline comprises one of our North System's main line sections that originate
at Bushton, Kansas and terminates at a storage and terminal area in Des Moines,
Iowa. We operate the Heartland pipeline, and ConocoPhillips operates Heartland's
Des Moines, Iowa terminal and serves as the managing partner of Heartland.
Heartland leases to ConocoPhillips Inc. 100% of the Heartland terminal capacity
at Des Moines, Iowa for $1.0 million per year on a year-to-year basis. The
Heartland pipeline lease fee, payable to us for
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reserved pipeline capacity, is paid monthly, with an annual adjustment. The 2005
lease fee will be approximately $1.1 million.
In addition, our North System has seven propane truck-loading terminals at
various points in three states along the pipeline system and one multi-product
complex at Morris, Illinois, in the Chicago area. Propane, normal butane and
natural gasoline can be loaded at our Morris terminal.
Markets. Our North System currently serves approximately 50 shippers in the
upper Midwest market, including both users and wholesale marketers of natural
gas liquids. These shippers include all three major refineries in the Chicago
area. Wholesale marketers of natural gas liquids primarily make direct large
volume sales to major end-users, such as propane marketers, refineries,
petrochemical plants and industrial concerns. Market demand for natural gas
liquids varies in respect to the different end uses to which natural gas liquids
products may be applied. Demand for transportation services is influenced not
only by demand for natural gas liquids but also by the available supply of
natural gas liquids. Heartland provides transportation of refined petroleum
products from refineries in the Kansas and Oklahoma areas to a BP terminal in
Council Bluffs, Iowa, a ConocoPhillips terminal in Lincoln, Nebraska and
Heartland's Des Moines terminal. The demand for, and supply of, refined
petroleum products in the geographic regions served by the Heartland pipeline
system directly affect the volume of refined petroleum products transported by
Heartland.
Supply. Natural gas liquids extracted or fractionated at the Bushton gas
processing plant have historically accounted for a significant portion
(approximately 40-50%) of the natural gas liquids transported through our North
System. Other sources of natural gas liquids transported in our North System
include large oil companies, marketers, end-users and natural gas processors
that use interconnecting pipelines to transport hydrocarbons. Refined petroleum
products transported by Heartland on our North System are supplied primarily
from the National Cooperative Refinery Association crude oil refinery in
McPherson, Kansas and the ConocoPhillips crude oil refinery in Ponca City,
Oklahoma.
During the first quarter of 2003, and again in the first quarter of 2004,
the North System experienced a general decline in throughput volumes due to a
lack of product supplies caused by shippers (primarily propane shippers)
reducing their inventory levels at the close of the winter season. In addition
to the general decline in throughput volumes, shippers were unable to get all of
their product out of the system, as a significant volume was required to be held
as line-fill. Following numerous discussions and meetings with our shippers in
an attempt to remedy this situation, including a plan to require shippers to
carry a minimum line-fill in our system, the consensus was for us to purchase
product to be used as line-fill and pass the carrying cost on to the shippers
through a cost of service filing with the FERC. A cost of service filing was
made with the FERC to be effective on June 1, 2004, raising our tariff rates by
$0.12 per barrel on product transported north of the Bushton/Conway, Kansas
area. This rate went into effect without protest or intervention.
Competition. Our North System competes with other natural gas liquids
pipelines and to a lesser extent with rail carriers. In most cases, established
pipelines are the lowest cost alternative for the transportation of natural gas
liquids and refined petroleum products. Consequently, pipelines owned and
operated by others represent our primary competition. With respect to the
Chicago market, our North System competes with other natural gas liquids
pipelines that deliver into the area and with rail car deliveries primarily from
Canada. Other Midwest pipelines and area refineries compete with our North
System for propane terminal deliveries. Our North System also competes
indirectly with pipelines that deliver product to markets that our North System
does not serve, such as the Gulf Coast market area. Heartland competes with
other refined petroleum product carriers in the geographic market served.
Heartland's principal competitor is Magellan Midstream Partners, L.P.
Plantation Pipe Line Company
We own approximately 51% of Plantation Pipe Line Company, a 3,100-mile
pipeline system serving the southeastern United States. An affiliate of
ExxonMobil owns the remaining 49% ownership interest. ExxonMobil is the largest
shipper on the Plantation system both in terms of volumes and revenues. We
operate the system pursuant to agreements with Plantation Services LLC and
Plantation Pipe Line Company. Plantation serves as a common carrier of refined
petroleum products to various metropolitan areas, including Birmingham, Alabama;
Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area.
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For the year 2004, Plantation delivered an average of 620,363 barrels per
day of refined petroleum products. These delivered volumes were comprised of
gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). Average delivery
volumes for 2004 were 1.3% higher than the 612,451 barrels per day delivered
during 2003. The increase was driven by regional demand growth in all
transportation-related fuels: gasoline up 0.9%; low sulfur diesel up 4.9%; and
jet fuel up 2.8%.
Markets. Plantation ships products for approximately 40 companies to
terminals throughout the southeastern United States. Plantation's principal
customers are Gulf Coast refining and marketing companies, fuel wholesalers, and
the United States Department of Defense. Plantation's top five shippers
represent slightly over 80% of total system volumes.
The eight states in which Plantation operates represent a collective
pipeline demand of approximately 2.0 million barrels per day of refined
products. Plantation currently has direct access to about 1.5 million barrels
per day of this overall market. The remaining 0.5 million barrels per day of
demand lies in markets (e.g. Nashville, Tennessee; North Augusta, South
Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by
another pipeline company. These markets represent potential growth opportunities
for the Plantation system.
In addition, Plantation delivers jet fuel to the Atlanta, Georgia;
Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National
and Dulles). Combined jet fuel shipments to these four major airports increased
1.5% (led by a 10% increase in shipments to Ronald Reagan National) in 2004. An
improving domestic economy should help improve jet fuel demand in 2005.
Supply. Products shipped on Plantation originate at various Gulf Coast
refineries from which major integrated oil companies and independent refineries
and wholesalers ship refined petroleum products. Plantation is directly
connected to and supplied by a total of nine major refineries representing over
two million barrels per day of refining capacity.
Competition. Plantation competes primarily with the Colonial pipeline
system, which also runs from Gulf Coast refineries throughout the southeastern
United States and extends into the northeastern states.
Kinder Morgan Southeast Terminals LLC
Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred
to in this report as KMST, was formed in 2003 for the purpose of acquiring and
operating high-quality liquid petroleum products terminals located primarily
along the Plantation/Colonial pipeline corridor in the Southeastern United
States.
On December 11, 2003, KMST acquired seven petroleum products terminals from
ConocoPhillips and Phillips Pipe Line Company for an aggregate consideration of
approximately $15.3 million, consisting of approximately $14.3 million in cash
and $1.0 million in assumed liabilities. These seven terminals contain
approximately 1.15 million barrels of storage capacity. The terminals are
located in the following markets: Selma, North Carolina; Charlotte, North
Carolina; Spartanburg, South Carolina; North Augusta, South Carolina; Doraville,
Georgia; Albany, Georgia; and Birmingham, Alabama. ConocoPhillips has entered
into a long-term contract to use the terminals. All seven terminals are served
by Colonial Pipeline and three are also connected to Plantation.
On March 9, 2004, KMST acquired seven additional refined petroleum products
terminals from Exxon Mobil Corporation for an aggregate consideration of
approximately $50.9 million, consisting of approximately $48.2 million in cash
and $2.7 million in assumed liabilities. The terminals are located at the
following locations: Newington, Virginia; Richmond, Virginia; Roanoke, Virginia;
Greensboro, North Carolina; Charlotte, North Carolina; Knoxville, Tennessee; and
Collins, Mississippi. The terminals have a combined storage capacity of
approximately 3.2 million barrels for gasoline, jet fuel and diesel fuel.
ExxonMobil has entered into a long-term contract to use the terminals. All seven
of these terminals are served by Plantation and two are also connected to
Colonial.
On November 5, 2004, KMST acquired ownership interests in nine additional
refined petroleum products terminals from Charter Terminal Company and
Charter-Triad Terminals, LLC for an aggregate consideration of
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approximately $75.2 million, consisting of approximately $72.4 million in cash
and $2.8 million in assumed liabilities. Three terminals are located in Selma,
North Carolina, and the remaining facilities are located in Greensboro and
Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia;
and North Augusta, South Carolina. The terminals have a combined storage
capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel
fuel. We fully own seven of the terminals and jointly own the remaining two. All
of the terminals are connected to products pipelines owned by either Plantation
Pipe Line Company or Colonial Pipeline Company. The acquisition increased our
southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal
throughput 62% (to over 340,000 barrels per day).
Markets. KMST acquisition and marketing activities are focused on the
Southeastern United States from Mississippi through Virginia, including
Tennessee and Florida. The primary marketing activity involves the receipt of
petroleum products from common carrier pipelines, short-term storage in terminal
tankage, and subsequent loading onto tank trucks. KMST has a physical presence
in markets representing almost 80% of the pipeline-supplied demand in the
Southeast and offers a competitive alternative to marketers seeking a
relationship with a truly independent truck terminal service provider.
Supply. Product supply is predominately from either Plantation, Colonial,
or both. To the maximum extent practicable, we try to connect KMST terminals to
both Plantation and Colonial.
Competition. There are relatively few independent terminal operators in the
Southeast. Most of the refined product terminals in this region are owned by
large oil companies (BP, Motiva, Citgo, Marathon Ashland, and Chevron) who use
these assets to support their own proprietary market demands as well as product
exchange activity. These oil companies are not generally seeking third party
throughput customers. Magellan Midstream Partners and TransMontaigne Product
Services represent the other independent terminal operators in this region.
Cochin Pipeline System
We own 49.8% of the Cochin pipeline system, a joint venture that operates
an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating
between Fort Saskatchewan, Alberta and Sarnia, Ontario. Effective October 1,
2004, we acquired our most recent ownership interest (5%) from subsidiaries of
ConocoPhillips. An affiliate of BP owns the remaining 50.2% ownership interest
and is the operator of the pipeline.
The Cochin pipeline system and related storage and processing facilities
consist of Canadian operations and United States operations:
o the Canadian facilities are operated under the name of Cochin Pipe
Lines, Ltd.; and
o the United States facilities are operated under the name of Dome
Pipeline Corporation.
The pipeline operates on a batched basis and has an estimated system
capacity of approximately 112,000 barrels per day. Its peak capacity is
approximately 124,000 barrels per day. It includes 31 pump stations spaced at 60
mile intervals and five United States propane terminals. Associated underground
storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario.
Markets. The pipeline traverses three provinces in Canada and seven states
in the United States transporting high vapor pressure ethane, ethylene, propane,
butane and natural gas liquids to the Midwestern United States and eastern
Canadian petrochemical and fuel markets. The system operates as a National
Energy Board (Canada) and Federal Energy Regulatory Commission (United States)
regulated common carrier, shipping products on behalf of its owners as well as
other third parties. The system is connected to the Enterprise pipeline system
in Minnesota and in Iowa, and connects with our North System at Clinton, Iowa.
The Cochin pipeline system has the ability to access the Canadian Eastern
Delivery System via the Windsor Storage Facility Joint Venture at Windsor,
Ontario.
Supply. Injection into the system can occur from:
o BP, EnerPro or Dow fractionation facilities at Fort Saskatchewan,
Alberta;
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o Provident Energy storage at five points within the provinces of
Canada; or
o the Enterprise West Junction, in Minnesota.
Competition. The pipeline competes with railcars and Enbridge Energy
Partners for natural gas liquids long-haul business from Fort Saskatchewan,
Alberta and Windsor, Ontario. The pipeline's primary competition in the Chicago
natural gas liquids market comes from the combination of the Alliance pipeline
system, which brings unprocessed gas into the United States from Canada, and
from Aux Sable, which processes and markets the natural gas liquids in the
Chicago market.
Cypress Pipeline
Our Cypress pipeline is an interstate common carrier pipeline system
originating at storage facilities in Mont Belvieu, Texas and extending 104 miles
east to the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20
miles east of Houston, is the largest hub for natural gas liquids gathering,
transportation, fractionation and storage in the United States.
Markets. The pipeline was built to service Westlake Petrochemicals
Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay
agreement that expires in 2011. The contract requires a minimum volume of 30,000
barrels per day.
Supply. The Cypress pipeline originates in Mont Belvieu where it is able to
receive ethane and ethane/propane mix from local storage facilities. Mont
Belvieu has facilities to fractionate natural gas liquids received from several
pipelines into ethane and other components. Additionally, pipeline systems that
transport specification natural gas liquids from major producing areas in Texas,
New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and
ethane/propane mix to Mont Belvieu.
Competition. The pipeline's primary competition into the Lake Charles
market comes from Louisiana onshore and offshore natural gas liquids.
Transmix Operations
Our transmix operations consist of liquid transmix processing facilities
located in Richmond, Virginia; Dorsey Junction, Maryland; Indianola,
Pennsylvania; Wood River, Illinois; and Colton, California. Transmix occurs when
dissimilar refined petroleum products are co-mingled in the pipeline
transportation process. Different products are pushed through the pipelines
abutting each other, and the area where different products mix is called
transmix. At our transmix processing facilities, we process and separate
pipeline transmix into pipeline-quality gasoline and light distillate products.
Transmix processing is performed for Duke Energy Merchants on a "for fee"
basis pursuant to a long-term contract expiring in 2010, and for Colonial
Pipeline Company at Dorsey Junction, Maryland. Effective September 30, 2004,
Shell Trading (U.S.) Company assumed ownership of the processing rights at our
transmix facilities located in Richmond, Virginia; Indianola, Pennsylvania; and
Wood River, Illinois. Shell Trading purchased the eastern transmix trading
business formerly owned by Duke Energy Merchants LLC, which included a transmix
processing agreement effective through March 16, 2011. At these locations, Shell
procures transmix supply from pipelines and other parties, pays a processing fee
to us, and then sells the processed gasoline and fuel oil through their
marketing and distribution networks. The arrangement includes a minimum
processing volume and fee to us, as well as an opportunity to extend the
processing agreement beyond the 2011 date.
Our Richmond processing facility is comprised of a dock/pipeline, a
170,000-barrel tank farm, a processing plant, lab and truck rack. The facility
is composed of three distillation units that operate 24 hours a day, 7 days a
week providing a processing capacity of approximately 8,000 barrels per day.
Both the Colonial and Plantation pipelines supply the facility, as well as
deep-water barge (25 feet draft), transport truck and rail. We also own an
additional 3.6-acre bulk products terminal, which is currently not in service,
with a capacity of 55,000 barrels located nearby in Richmond.
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Our Dorsey Junction processing facility is located near Baltimore, Maryland
within Colonial's Dorsey Junction terminal facility. The 5,000-plus barrel per
day processing unit began operations in February 1998. It operates 24 hours a
day, 7 days a week providing dedicated transmix separation service for Colonial.
Our Indianola processing facility is located near Pittsburgh, Pennsylvania
and is accessible by truck, barge and pipeline. It primarily processes transmix
from Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process
12,000 barrels of transmix per day and operates 24 hours per day, 7 days a week.
The facility is comprised of a 500,000-barrel tank farm, a quality control
laboratory, a truck-loading rack and a processing unit. The facility can ship
output via the Buckeye pipeline as well as by truck.
Our Wood River processing facility was constructed in 1993 on property
owned by ConocoPhillips and is accessible by truck, barge and pipeline. It
primarily processes transmix from both Explorer and ConocoPhillips pipelines. It
has capacity to process 5,000 barrels of transmix per day. Located on
approximately three acres leased from ConocoPhillips, the facility consists of
one processing unit. Supporting terminal capability is provided through leased
tanks in adjacent terminals.
Our Colton processing facility, completed in the spring of 1998, and
located adjacent to our products terminal in Colton, California, produces
refined petroleum products that are delivered into our Pacific operations'
pipelines for shipment to markets in Southern California and Arizona. The
facility can process over 5,000 barrels per day.
Markets. The Gulf and East Coast refined petroleum products distribution
system, particularly the Mid-Atlantic region, provides the target market for our
East Coast transmix processing operations. The Mid-Continent area and the New
York Harbor are the target markets for our Pennsylvania and Illinois assets. Our
West Coast transmix processing operations support the markets served by our
Pacific operations. We are working to expand our Mid-Continent and West Coast
markets.
Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer
and our Pacific operations provide the vast majority of the supply. These
suppliers are committed to our transmix facilities by long-term contracts.
Individual shippers and terminal operators provide additional supply. Duke
Energy Merchants is responsible for acquiring transmix supply at Colton, and
Shell acquires transmix for processing at Indianola, Richmond and Wood River.
The Dorsey Junction facility is supplied by Colonial Pipeline Company.
Competition. Placid Refining is our main competitor in the Gulf Coast area.
There are various processors in the Mid-Continent area, primarily
ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with
our expansion efforts in that market. A number of smaller organizations operate
transmix processing facilities in the West and Southwest. These operations
compete for supply that we envision as the basis for growth in the West and
Southwest. Our Colton processing facility also competes with major oil company
refineries in California.
Natural Gas Pipelines
Our Natural Gas Pipelines segment, which contains both interstate and
intrastate pipelines, consists of natural gas sales, transportation, storage,
gathering, processing and treating. Within this segment, we own approximately
14,000 miles of natural gas pipelines and associated storage and supply lines
that are strategically located at the center of the North American pipeline
grid. Our transportation network provides access to the major gas supply areas
in the western United States, Texas and the Midwest, as well as major consumer
markets. Our Natural Gas Pipeline assets include the following:
o our Texas intrastate natural gas pipeline group, which operates
primarily along the Texas Gulf Coast and includes the following four
pipeline systems: Kinder Morgan Texas Pipeline, Kinder Morgan Tejas,
Mier-Monterrey Mexico Pipeline, and the North Texas Pipeline. Kinder
Morgan Texas and Kinder Morgan Tejas are the two largest systems in
this group, and combined, consist of approximately 5,800 miles of
intrastate natural gas pipelines with a peak transport capacity of
approximately five billion cubic feet per day of natural gas and
approximately 120 billion cubic feet of natural gas storage capacity
(including the West Clear Lake natural gas storage facility located in
Harris County, Texas, which is committed under a long term contract to
Coral Energy);
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o our three Rocky Mountain interstate natural gas pipeline systems:
Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline
Company and TransColorado Gas Transmission Company. KMIGT owns a
4,562-mile natural gas pipeline system, including the Pony Express
pipeline system, that extends from northwestern Wyoming east into
Nebraska and Missouri and south through Colorado and Kansas. Our
Trailblazer pipeline is a 436-mile pipeline that transports natural
gas from Colorado to Beatrice, Nebraska. TransColorado owns a 300-mile
natural gas pipeline system that extends from the Western Slope of
Colorado to northwestern New Mexico. As of December 31, 2004, the
combined peak transport capacity for our Rocky Mountain pipeline
systems was approximately 2.5 billion cubic feet per day of natural
gas, and the combined storage capacity was approximately 10.0 billion
cubic feet of natural gas;
o our Casper and Douglas natural gas gathering systems, which are
comprised of over 1,500 miles of natural gas gathering pipelines and
two facilities in Wyoming capable of processing 210 million cubic feet
of natural gas per day;
o our 49% interest in the Red Cedar Gathering Company, which gathers
natural gas in La Plata County, Colorado and owns and operates two
carbon dioxide processing plants;
o our 50% interest in Coyote Gas Treating, LLC, which owns a 250 million
cubic feet per day natural gas treating facility in La Plata County,
Colorado; and
o our 25% interest in Thunder Creek Gas Services, LLC, which gathers,
transports and processes methane gas from coal beds in the Powder
River Basin of Wyoming.
Texas Intrastate Pipeline Group
Our Kinder Morgan Tejas system was acquired on January 31, 2002 from
Intergen, a joint venture owned by affiliates of the Royal Dutch Shell Group of
Companies, and Bechtel Enterprises Holding, Inc. The system has become
increasingly interconnected with our Kinder Morgan Texas Pipeline system, which
was acquired on December 31, 1999 from KMI. These pipelines essentially operate
as a single pipeline system, providing customers and suppliers with improved
flexibility and reliability. The combined assets include over 5,800 miles of
natural gas pipelines with a peak transport capacity of approximately five
billion cubic feet per day and approximately 120 billion cubic feet of natural
gas storage capacity. In addition, the system, through owned assets and
contractual arrangement with third parties, has the capability to process over
one billion cubic feet per day of natural gas for liquids extraction and treat
approximately 250 million cubic feet per day of natural gas for carbon dioxide
removal.
Collectively, the system primarily serves the Texas Gulf Coast,
transporting, processing and treating gas from multiple onshore and offshore
supply sources to serve the Houston/Beaumont/Port Arthur, Texas industrial
markets, as well as local gas distribution utilities, electric utilities and
merchant power generation markets. It serves as a buyer and seller of natural
gas, as well as a transporter of natural gas. The purchases and sales of natural
gas are primarily priced with reference to market prices in the consuming region
of its system. The difference between the purchase and sale prices is the rough
equivalent of a transportation fee.
Our North Texas Pipeline, a $65 million investment, was completed in August
2002. The system consists of an 86-mile, 30-inch diameter pipeline that
transports natural gas from an interconnect with KMI's Natural Gas Pipeline
Company of America in Lamar County, Texas to a 1,750-megawatt electric
generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It
has the capacity to transport 325,000 dekatherms per day of natural gas and is
fully subscribed under a 30 year contract.
Our Mier-Monterrey Pipeline, an $89 million investment, was completed in
March 2003. The system consists of a 95-mile, 30-inch diameter natural gas
pipeline that stretches from south Texas to Monterrey, Mexico and can transport
up to 375,000 dekatherms per day. The pipeline connects to a 1,000-megawatt
power plant complex and to the PEMEX natural gas transportation system. We have
entered into a 15 year contract with Pemex Gas Y Petroquimica Basica, which has
subscribed for all of the pipeline's capacity.
Markets. Our Texas intrastate natural gas pipeline group's market area
consumes over eight billion cubic feet per day of natural gas. Of this amount,
we estimate that 75% is industrial demand (including on-site, cogeneration
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facilities), about 15% is merchant generation demand and the remainder is split
between local natural gas distribution and utility power demand. The industrial
demand is primarily year-round load. Local natural gas distribution load peaks
in the winter months and is complemented by power demand (both merchant and
utility generation) which peaks in the summer months. As new merchant gas fired
generation has come online and displaced traditional utility generation, we have
successfully attached certain of these new generation facilities to our pipeline
systems in order to maintain our share of natural gas supply for power
generation.
We serve the Mexico market through interconnection with the facilities of
Pemex at the United States-Mexico border near Arguellas, Mexico and Monterrey,
Mexico. Current deliveries through the existing interconnection near Arguellas
are approximately 150,000 to 200,000 dekatherms per day of natural gas and
deliveries to Monterrey generally range from 150,000 to 300,000 dekatherms per
day. We primarily provide transport service to these markets on a fee for
service basis, including a significant demand component, which is paid
regardless of actual throughput. Revenues earned from our activities in Mexico
are paid in U.S. dollar equivalent.
Supply. We purchase our natural gas directly from producers attached to our
system in South Texas, East Texas and along the Texas Gulf Coast. We also
purchase gas at interconnects with third-party interstate and intrastate
pipelines. While our intrastate group does not produce gas, it does maintain an
active well connection program in order to offset natural declines in production
along its system and to secure supplies for additional demand in its market
area. Our intrastate system has access to both onshore and offshore sources of
supply, and is well positioned to interconnect with liquefied natural gas
projects currently under development by others along the Texas Gulf Coast.
Gathering, Processing and Treating. Our intrastate natural gas group owns
and operates various gathering systems in South and East Texas. These systems
aggregate pipeline quality natural gas supplies into our main transmission
pipelines, and in certain cases, aggregate natural gas that must be processed or
treated at its own or third-party facilities. We own two processing plants: our
Texas City Plant in Galveston County, Texas and our Galveston Bay Plant in
Chambers County, Texas, which is currently idle. Combined, these plants can
process 115 million cubic feet per day of natural gas for liquids extraction. In
addition, we have contractual rights to process approximately 735 million cubic
feet per day of natural gas at various third-party owned facilities. We also own
and operate four natural gas treating plants that offer carbon dioxide and/or
hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of
natural gas for carbon dioxide removal at our Fandango Complex in Zapata County,
Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in
Upshur County, Texas and approximately 45 million cubic feet per day of natural
gas at our Thompsonville Facility located in Jim Hogg County, Texas.
Storage. We own the West Clear Lake natural gas storage facility located in
Harris County, Texas. Under a long term contract, Coral Energy Resources, L.P.
operates the facility and controls the 96 billion cubic feet of natural gas
working capacity, and we provide transportation service into and out of the
facility. We lease a salt dome storage facility located near Markham, Texas. The
facility consists of two salt dome caverns with approximately 7.5 billion cubic
feet of total natural gas storage capacity, over 4.2 billion cubic feet of
working natural gas capacity and up to 500 million cubic feet per day of peak
deliverability. We also lease salt dome caverns from Dow Hydrocarbon &
Resources, Inc. and BP America Production Company in Brazoria County, Texas. The
salt dome caverns are referred to as the Stratton Ridge Facilities and have a
combined capacity of 11.8 billion cubic feet of natural gas, working natural gas
capacity of 5.4 billion cubic feet and a peak day deliverability of up to 400
million cubic feet per day.
Competition. The Texas intrastate natural gas market is highly competitive,
with many markets connected to multiple pipeline companies. We compete with
interstate and intrastate pipelines, and their shippers, for attachments to new
markets and supplies and for transportation, processing and treating services.
Kinder Morgan Interstate Gas Transmission LLC
Kinder Morgan Interstate Gas Transmission LLC, referred to in this report
as KMIGT, owns approximately 4,562 miles of transmission lines in Wyoming,
Colorado, Kansas, Missouri and Nebraska. It provides transportation and storage
services to KMI affiliates, third-party natural gas distribution utilities and
other shippers. KMIGT also has the authority to make gas purchases and sales, as
needed for system operations, pursuant to its currently
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effective FERC gas tariff. Pursuant to transportation agreements and Federal
Energy Regulatory Commission tariff provisions, KMIGT offers its customers firm
and interruptible transportation and storage services, including no-notice
transportation and park and loan services. Under KMIGT's tariffs, firm
transportation and storage customers pay reservation fees each month plus a
commodity charge based on the actual transported or stored volumes. In contrast,
interruptible transportation and storage customers pay a commodity charge based
upon actual transported and/or stored volumes. Reservation fees are based upon
geographical location (KMIGT does not have seasonal rates) and the distance of
the transportation service provided. Under the no-notice service, customers pay
a fee for the right to use a combination of firm storage and firm transportation
to effect deliveries of natural gas up to a specified volume without making
specific nominations.
The system is powered by 28 transmission and storage compressor stations
with approximately 160,000 horsepower. The pipeline system provides storage
services to its customers from its Huntsman Storage Field in Cheyenne County,
Nebraska. On June 1, 2004, KMIGT implemented its Cheyenne Market Center service,
which provides nominated storage and transportation service between its Huntsman
Storage Field and multiple interconnecting pipelines at the Cheyenne Hub. This
service is fully subscribed for a period of ten years and added an incremental
withdrawal capacity of 68 million cubic feet of natural gas per day and
increased the working gas capacity by 3.5 billion cubic feet. The Huntsman
Storage facility now has approximately 39.5 billion cubic feet of total storage
capacity, 16 billion cubic feet of working gas capacity and can withdraw up to
169 million cubic feet of natural gas per day.
Markets. Markets served by KMIGT provide a stable customer base with
expansion opportunities due to the system's access to growing Rocky Mountain
supply sources. Markets served by KMIGT are comprised mainly of local natural
gas distribution companies and interconnecting interstate pipelines in the
mid-continent area. End-users of the local natural gas distribution companies
typically include residential, commercial, industrial and agricultural
customers. The pipelines interconnecting with KMIGT in turn deliver gas into
multiple markets including some of the largest population centers in the
Midwest. Natural gas demand to power pumps for crop irrigation during the summer
from time-to-time exceeds heating season demand and provides KMIGT relatively
consistent volumes throughout the year.
Supply. Approximately 15%, by volume, of KMIGT's firm contracts expire
within one year and 39% expire within one to five years. Our affiliates are
responsible for approximately 21% of the total contracted firm transportation
and storage capacity on KMIGT's system. Over 98% of the system's firm transport
capacity is currently subscribed.
Competition. KMIGT competes with other interstate and intrastate gas
pipelines transporting gas from the supply sources in the Rocky Mountain and
Hugoton Basins to mid-continent pipelines and market centers.
Trailblazer Pipeline Company
Trailblazer Pipeline Company is an Illinois partnership and its principal
business is to transport natural gas in interstate commerce. It does business in
the states of Wyoming, Colorado and Nebraska. Natural Gas Pipeline Company of
America, a subsidiary of KMI, manages, maintains and operates Trailblazer, for
which it is reimbursed at cost. Trailblazer's 436-mile natural gas pipeline
system originates at an interconnection with Wyoming Interstate Company Ltd.'s
pipeline system near Rockport, Colorado and runs through southeastern Wyoming to
a terminus near Beatrice, Nebraska where it interconnects with Natural Gas
Pipeline Company of America's and Northern Natural Gas Company's pipeline
systems.
Trailblazer's pipeline is the fourth and last segment of a 791-mile
pipeline system known as the Trailblazer Pipeline System, which originates in
Uinta County, Wyoming with Canyon Creek Compression Company, a 22,000 horsepower
compressor station located at the tailgate of BP Amoco Production Company's
processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek's
facilities are the first segment). Canyon Creek receives gas from the BP Amoco
processing plant and provides transportation and compression of gas for delivery
to Overthrust Pipeline Company's 88-mile, 36-inch diameter pipeline system at an
interconnection in Uinta County, Wyoming (Overthrust's system is the second
segment). Overthrust delivers gas to Wyoming Interstate's 269-mile, 36-inch
diameter pipeline system at an inter-connection (Kanda) in Sweetwater County,
Wyoming (Wyoming Interstate's system is the third segment). Wyoming Interstate's
pipeline delivers gas to Trailblazer's pipeline at an
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interconnection near Rockport in Weld County, Colorado.
Trailblazer provides transportation services to third-party natural gas
producers, marketers, gathering companies, local distribution companies and
other shippers. Pursuant to transportation agreements and FERC tariff
provisions, Trailblazer offers its customers firm and interruptible
transportation. Under Trailblazer's tariffs, firm transportation customers pay
reservation charges each month plus a commodity charge based on actual volumes
transported. Interruptible transportation customers pay a commodity charge based
upon actual volumes transported.
Markets. Significant growth in Rocky Mountain natural gas supplies has
prompted a need for additional pipeline transportation service. Trailblazer has
a certificated capacity of 846 million cubic feet per day of natural gas.
Supply. As of December 31, 2004, 6% of Trailblazer's firm contracts, by
volume, expire before one year and 40%, by volume, expire within one to five
years. Affiliated entities hold less than 1% of the total firm transportation
capacity. All of the system's firm transport capacity is currently subscribed.
Competition. The main competition that Trailblazer currently faces is that
the gas supply in the Rocky Mountain area either stays in the area or is moved
west and therefore is not transported on Trailblazer's pipeline. However, on
March 24, 2004, the FERC issued a certificate approving the Cheyenne Plains
pipeline project that was developed by Colorado Interstate Gas Company. This
project, which commenced service in December 2004, allows for the transportation
of 560,000 dekatherms per day of natural gas from Weld County, Colorado to
Greensburg, Kansas and competes with Trailblazer for natural gas pipeline
transportation demand from the Rocky Montitain area. In addition, Cheyenne
Plains received approval from the FERC to expand its facilities to provide an
additional 170,000 dekatherms per day of capacity for a total capacity of
730,000 dekatherms. The proposed expansion is anticipated to go into service in
early 2006. No assurance can be given that additional competing pipelines will
not be developed in the future.
TransColorado Gas Transmission Company
TransColorado Gas Transmission Company is a Colorado general partnership
that owns a 300-mile interstate natural gas pipeline that extends form the
Western Slope of Colorado to northwestern New Mexico. KMIGT manages, maintains
and operates TransColorado, for which it is reimbursed at cost. We acquired all
of the ownership interests in TransColorado from KMI effective November 1, 2004.
The TransColorado Pipeline, which extends from approximately 20 miles southwest
of Meeker, Colorado to Bloomfield, New Mexico, has 20 points of interconnection
with five interstate pipelines, one intrastate pipeline, eight gathering
systems, and two local distribution companies, thereby providing relatively
significant flexibility in the receipt and delivery of natural gas. The pipeline
system is powered by five compressor stations in mainline service having an
aggregate of approximately 26,500 horsepower.
Gas flowing south through the pipeline moves onto the El Paso, Transwestern
and Southern Trail pipeline systems. TransColorado receives gas from two coal
seam natural gas treating plants located in the San Juan Basin of Colorado and
from pipeline and gathering system interconnections within the Paradox and
Piceance Basins of western Colorado. TransColorado provides transportation
services to third-party natural gas producers, marketers, gathering companies,
local distribution companies and other shippers. Pursuant to transportation
agreements and FERC tariff provisions, TransColorado offers its customers firm
and interruptible transportation and interruptible park and loan services. Under
TransColorado's tariffs, firm transportation customers pay reservation charges
each month plus a commodity charge based on actual volumes transported.
Interruptible transportation customers pay a commodity charge based upon actual
volumes transported. The underlying reservation and commodity charges are
assessed pursuant to a maximum recourse rate structure, which does not vary
based on the distance gas is transported. TransColorado has the authority to
negotiate rates with customers if it has first offered service to those
customers under its reservation and commodity charge rate structure.
TransColorado's revenues and volumes have historically been higher during
the second and third quarters of the calendar year, resulting from two factors:
winter heating market loads to the north of TransColorado and summer air
conditioning market loads to the south of TransColorado.
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Markets. TransColorado acts principally as a feeder pipeline system from
the developing natural gas supply basins on the Western Slope of Colorado into
the interstate natural gas pipelines that lead away from the Blanco Hub area of
New Mexico. TransColorado is the largest transporter of natural gas from the
Western Slope supply basins of Colorado and provides a competitively attractive
outlet for that developing natural gas resource. In 2004, TransColorado
transported an average of 518,495 dekatherms per day of natural gas from these
supply basins. TransColorado provides a strategically important link between the
underdeveloped gas supply resources on the Western Slope of Colorado and the
greater southwestern United States marketplace.
Supply. During 2004, 73% of TransColorado's transport business was with
producers or their own marketing affiliates, 4% was with third-party marketers
and the remaining 23% was primarily with gathering companies. Approximately 70%
of TransColorado's transport business in 2004 was conducted with its three
largest customers. All of TransColorado's pipeline capacity is committed under
firm transportation contracts that extend at least through year-end 2007.
TransColorado's pipeline capacity is 65% subscribed during 2007 through 2011 and
TransColorado is actively pursuing contract extensions and or replacement
contracts to increase firm subscription levels beyond 2007.
On October 6, 2004, TransColorado announced an approximate $20 million
expansion project to add 300,000 dekatherms per day of incremental natural gas
transportation capacity. As a result of this expansion, natural gas on the
northern portion of TransColorado's pipeline will be able to flow northward as
well as southward. The expansion is supported by a long-term contract with an
undisclosed shipper and includes commitments for up to 280,000 dekatherms per
day of natural gas. The contract runs through 2015 with an option for a 5-year
extension.
Competition. TransColorado competes with other transporters of natural gas
in each of the natural gas supply basins it serves. These competitors include
both interstate and intrastate natural gas pipelines and natural gas gathering
systems. TransColorado is the most recent interstate pipeline entrant into each
of the competitive supply markets of the Paradox, Piceance and San Juan Basins
of western Colorado. Notwithstanding this fact, we believe that TransColorado
generally is looked upon favorably by shippers because it provides distinct
advantages of larger system capacity and more direct access to market outlets
than its competitors.
TransColorado's shippers compete for market share with shippers drawing
upon gas production facilities within the New Mexico portion of the San Juan
Basin. TransColorado has phased its past construction and expansion efforts to
coincide with the ability of the interstate pipeline grid at Blanco, New Mexico
to accommodate greater natural gas volumes. The overall San Juan Basin gas
production base had been a perennial factor restricting the growth pace of
TransColorado's transport from the central Rockies natural gas supply basins.
Natural gas production from the San Juan Basin peaked during the first quarter
of 2000 and has since declined on an overall basis by 10%. TransColorado's
transport concurrently ramped up over that period such that TransColorado now
enjoys a growing share of the outlet from the San Juan Basin to the southwestern
United States marketplace.
Historically, the competition faced by TransColorado with respect to its
natural gas transportation services has generally been based upon the price
differential between the San Juan and Rocky Mountain basins. The Kern River Gas
Transmission expansion project, placed in service in May 2003, has had the
effect of reducing that price differential. However, given the increased number
of direct connections to production facilities in the Piceance and Paradox
basins and the aggressive gas supply development in each of those basins, we
believe that TransColorado's transport business will be less susceptible to
changes in the price differential in the future.
Casper and Douglas Natural Gas Gathering and Processing Systems
We own and operate our Casper and Douglas natural gas gathering and
processing facilities.
The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet
per day of natural gas from 650 active receipt points. Douglas Gathering has an
aggregate 20,650 horsepower of compression situated at 17 field compressor
stations. Gathered volumes are processed at our Douglas plant, located in
Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are
injected in ConocoPhillips Petroleum's natural gas liquids pipeline for
transport to Borger, Texas.
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The Casper gathering system is comprised of approximately 32 miles of
4-inch to 8-inch diameter pipeline gathering approximately four million cubic
feet per day of natural gas from four active receipt points. Gathered volumes
are delivered directly into KMIGT. Current gathering capacity is contingent upon
available capacity on KMIGT and the Casper Plant's 50 to 80 million cubic feet
per day processing capacity.
We believe that Casper-Douglas' unique combination of
percentage-of-proceeds, sliding scale percent-of-proceeds and keep whole plus
fee processing agreements helps to reduce our exposure to commodity price
volatility.
Markets. Casper and Douglas are processing plants servicing gas streams
flowing into KMIGT.
Competition. There are three other natural gas gathering and processing
alternatives available to conventional natural gas producers in the Greater
Powder River Basin. However, Casper and Douglas are the only two plants in the
region that provide straddle processing of natural gas streams flowing into
KMIGT upstream of our two plant facilities. The other regional facilities
include the Hilight (80 million cubic feet per day) and Kitty (17 million cubic
feet per day) plants owned and operated by Western Gas Resources, and the Sage
Creek Processors (50 million cubic feet per day) plant owned and operated by
Merit Energy.
Red Cedar Gathering Company
We own a 49% equity interest in the Red Cedar Gathering Company, a joint
venture organized in August 1994, referred to in this report as Red Cedar. The
Southern Ute Indian Tribe owns the remaining 51%. Red Cedar owns and operates
natural gas gathering, compression and treating facilities in the Ignacio Blanco
Field in La Plata County, Colorado. The Ignacio Blanco Field lies within the
Colorado portion of the San Juan Basin, most of which is located within the
exterior boundaries of the Southern Ute Indian Tribe Reservation. Red Cedar
gathers coal seam and conventional natural gas at wellheads and several central
delivery points, for treating, compression and delivery into any one of four
major interstate natural gas pipeline systems and an intrastate pipeline.
Red Cedar's gas gathering system currently consists of over 900 miles of
gathering pipeline connecting more than 700 producing wells, 82,000 horsepower
of compression at 22 field compressor stations and two carbon dioxide treating
plants. A majority of the natural gas on the system moves through 8-inch to
16-inch diameter pipe. The capacity and throughput of the Red Cedar system as
currently configured is approximately 750 million cubic feet per day of natural
gas.
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture that was organized
in December 1996. Enterprise Field Services LLC owns the remaining 50%. The sole
asset owned by the joint venture is a 250 million cubic feet per day natural gas
treating facility located in La Plata County, Colorado. We are the managing
partner of Coyote Gas Treating, LLC.
The inlet gas stream treated by Coyote Gulch contains an average carbon
dioxide content of between 12% and 13%. The plant treats the gas down to a
carbon dioxide concentration of 2% in order to meet interstate natural gas
pipeline quality specifications, and then compresses the natural gas into the
TransColorado Gas Transmission pipeline for transport to the Blanco, New
Mexico-San Juan Basin Hub.
Effective January 1, 2002, Coyote Gulch entered into a five-year operating
lease agreement with Red Cedar. Under the terms of the lease, Red Cedar operates
the facility and is responsible for all operating and maintenance expense and
capital costs. In place of the treating fees that were previously received by
Coyote Gulch from Red Cedar, Red Cedar is required to make monthly lease
payments.
Thunder Creek Gas Services, LLC
We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred
to in this report as Thunder Creek. Thunder Creek is a joint venture that was
organized in September 1998. Devon Energy owns the remaining 75%. Thunder Creek
provides gathering, compression and treating services to a number of coal seam
gas producers in the Powder River Basin. Throughput volumes include both coal
seam and conventional plant residue gas. Thunder
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Creek is independently operated from offices located in Denver, Colorado with
field offices in Glenrock and Gillette, Wyoming.
Thunder Creek's operations are a combination of mainline and low pressure
gathering assets. The mainline assets include 125 miles of 24-inch diameter
mainline pipeline, 308 miles of 4-inch to 12-inch diameter high and low pressure
laterals, 19,620 horsepower of mainline compression and carbon dioxide removal
facilities consisting of a 240 million cubic feet per day carbon dioxide
treating plant complete with dehydration. The mainline assets receive gas from
41 receipt points and can deliver treated gas to seven delivery points including
Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power
plants. The low pressure gathering assets include five systems consisting of 185
miles of 4-inch to 14-inch diameter gathering pipeline and 40,852 horsepower of
field compression. Gas is gathered from 79 receipt points and delivered to the
mainline at seven primary locations.
CO2
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to in this report as KMCO2. Carbon dioxide is
used in enhanced oil recovery projects as a flooding medium for recovering crude
oil from mature oil fields. Our carbon dioxide pipelines and related assets
allow us to market a complete package of carbon dioxide supply, transportation
and technical expertise to the customer. Together, our CO2 business segment
produces, transports and markets carbon dioxide for use in enhanced oil recovery
operations and owns interests in other related assets in the continental United
States, through the following:
o our interests in carbon dioxide reserves, including an approximate 45%
interest in the McElmo Dome unit and an approximate 11% interest in
the Bravo Dome unit;
o our carbon dioxide pipelines, including:
o our Central Basin pipeline, a 321-mile carbon dioxide pipeline
system located in the Permian Basin of West Texas between Denver
City, Texas and McCamey, Texas;
o our Centerline pipeline, a 113-mile carbon dioxide pipeline
located in the Permian Basin of West Texas between Denver City,
Texas and Snyder, Texas; and
o our interests in other carbon dioxide pipelines, including an
approximate 98% interest in the Canyon Reef Carriers pipeline, a
50% interest in the Cortez pipeline, a 13% undivided interest in
the Bravo pipeline system and an approximate 69% interest in the
Pecos pipeline;
o our interests in oil-producing fields, including an approximate 97%
working interest in the SACROC unit, an approximate 50% working
interest in the Yates unit, a 22% net profits interest in the H.T.
Boyd unit and lesser interests in the Sharon Ridge unit, the Reinecke
unit and the MidCross unit, all of which are located in the Permian
Basin of West Texas;
o our interests in gasoline plants, including an approximate 22% working
interest and an additional 26% net profits interest in the Snyder
gasoline plant, a 51% ownership interest in the Diamond M gas plant
and a 100% ownership interest in the North Snyder plant, all of which
are located in the Permian Basin of West Texas; and
o our 450-mile Wink crude oil pipeline system located in West Texas and
used to transport crude oil from the Permian Basin to Western Refining
Company, L.P.'s crude oil refinery located in El Paso, Texas.
Carbon Dioxide Reserves
We own approximately 45% of, and operate, the McElmo Dome unit, which
contains more than 10 trillion cubic feet of carbon dioxide. Deliverability and
compression capacity exceeds one billion cubic feet per day. The McElmo Dome
unit produces from the Leadville formation at approximately 8,000 feet with 49
wells that produce at individual rates of up to 53 million cubic feet per day.
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We also own approximately 11% of Bravo Dome unit, which holds reserves of
approximately two trillion cubic feet of carbon dioxide. The Bravo dome produces
approximately 307 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.
Markets. Our principal market for carbon dioxide is for injection into
mature oil fields in the Permian Basin, where industry demand is expected to be
comparable to historical demand for the next several years. We are exploring
additional potential markets, including enhanced oil recovery targets in the
North Sea, California, Mexico and coal bed methane production in the San Juan
Basin of New Mexico.
Competition. Our primary competitors for the sale of carbon dioxide include
suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep
Mountain carbon dioxide reserves, and Petro-Source Carbon Company, which gathers
waste carbon dioxide from natural gas production in the Val Verde Basin of West
Texas. There is no assurance that new carbon dioxide sources will not be
discovered or developed, which could compete with us or that new methodologies
for enhanced oil recovery will not replace carbon dioxide flooding.
Carbon Dioxide Pipelines
Placed in service in 1985, our Central Basin pipeline consists of
approximately 143 miles of 16-inch to 20-inch diameter pipe and 178 miles of
4-inch to 12-inch lateral supply lines located in the Permian Basin between
Denver City, Texas and McCamey, Texas with a throughput capacity of 650 million
cubic feet per day. At its origination point in Denver City, our Central Basin
pipeline interconnects with all three major carbon dioxide supply pipelines from
Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the
Bravo and Sheep Mountain pipelines (operated by Occidental and Trinity CO2,
respectively). Central Basin's mainline terminates near McCamey where it
interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The
tariffs charged by the Central Basin pipeline are not regulated.
Our Centerline pipeline consists of approximately 113 miles of 16-inch
diameter pipe located in the Permian Basin between Denver City, Texas and
Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. We
constructed this pipeline and placed it in service in May 2003. The tariffs
charged by the Centerline pipeline are not regulated.
As a result of our 50% ownership interest in Cortez Pipeline Company, we
own a 50% interest in and operate the 502-mile, 30-inch diameter Cortez
pipeline. The pipeline carries carbon dioxide from the McElmo Dome source
reservoir in Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline
currently transports nearly one billion cubic feet of carbon dioxide per day,
including approximately 90% of the carbon dioxide transported downstream on our
Central Basin pipeline and our Centerline pipeline.
We own a 13% undivided interest in the 218-mile, 20-inch diameter Bravo
pipeline, which delivers to the Denver City hub and has a capacity of more than
350 million cubic feet per day. Major delivery points along the line include the
Slaughter field in Cochran and Hockley Counties, Texas, and the Wasson field in
Yoakum County, Texas. Tariffs on the Cortez and Bravo pipelines are not
regulated.
In addition, we own approximately 98% of the Canyon Reef Carriers pipeline
and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 138 miles from McCamey, Texas, to the SACROC unit. The pipeline has a
16-inch diameter, a capacity of approximately 290 million cubic feet per day and
makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The
Pecos pipeline is a 25-mile, 8-inch diameter pipeline that runs from McCamey to
Iraan, Texas. We acquired an additional 65% ownership interest in the pipeline
on November 1, 2003 from a subsidiary of Marathon Oil Company and are currently
delivering through it approximately 70 million cubic feet per day of carbon
dioxide.
Markets. The principal market for transportation on our carbon dioxide
pipelines is to customers using carbon dixoide for enhanced recovery operations
in mature oil fields in the Permian Basin, where industry demand is expected to
be comparable to historical demand for the next several years.
Competition. Our ownership interests in the Central Basin, Cortez and Bravo
pipelines are in direct competition with other carbon dioxide pipelines. We also
compete with other interest owners in McElmo Dome and Bravo
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Dome for transportation of carbon dioxide to the Denver City, Texas market area.
Oil Reserves
The SACROC unit is one of the largest and oldest oil fields in the United
States using carbon dioxide flooding technology. The field is comprised of
approximately 56,000 acres located in the Permian Basin in Scurry County, Texas.
SACROC was discovered in 1948 and has produced over 1.27 billion barrels of oil
since inception. We have continued the development of the carbon dioxide project
initiated by the previous owners and have reversed the decline in production
through increased carbon dioxide injection.
Effective June 1, 2003, we increased our interest in SACROC to
approximately 97% by acquiring MKM Partners, L.P.'s 12.75% ownership interest.
MKM Partners, L.P. was an oil and gas joint venture formed on January 1, 2001
and owned 15% by KMCO2 and 85% by subsidiaries of Marathon Oil Company. The
joint venture's assets consisted of a 12.75% interest in the SACROC field unit
and a 49.9% interest in the Yates field unit. MKM Partners, L.P. was dissolved
effective June 30, 2003, and its net assets were distributed to its partners in
accordance with its partnership agreement.
As of December 2004, the SACROC unit had 332 producing wells, and the
purchased carbon dioxide injection rate was 339 million cubic feet per day, up
from an average of 317 million cubic feet per day as of December 2003. The oil
production rate as of December 2004 was approximately 33,000 barrels of oil per
day, up from approximately 23,000 barrels of oil per day as of December 2003.
The Yates unit is also one of the largest oil fields ever discovered in the
United States. It is estimated that it originally held more than five billion
barrels of oil, of which about 28% has been produced. The field, discovered in
1926, is comprised of approximately 26,000 acres located about 90 miles south of
Midland, Texas. Effective November 1, 2003, we increased our interest in Yates
and became operator of the field by acquiring an additional 42.5% ownership
interest from subsidiaries of Marathon Oil Company. We also acquired the crude
oil gathering lines and equipment surrounding the Yates field. We now own a
nearly 50% ownership interest in the Yates field unit.
As of December 2003, the Yates unit was producing about 18,000 barrels of
oil per day. Our plan has been to increase the production life of Yates by
combining horizontal drilling with carbon dioxide flooding to ensure a
relatively steady production profile over the next several years. We are
implementing our plan and as of December 2004, the Yates unit was producing
approximately 22,000 barrels of oil per day. Unlike our operations at SACROC,
where we use carbon dioxide and water to drive oil to the producing wells, we
plan on using carbon dioxide injection to replace nitrogen injection at Yates in
order to enhance the gravity drainage process, as well as to maintain reservoir
pressure. The differences in geology and reservoir mechanics between the two
fields mean that substantially less capital will be needed to develop the
reserves at Yates than is required at SACROC.
The following table sets forth productive wells, service wells and drilling
wells in the oil and gas fields in which we own interests as of December 31,
2004:
Productive Wells (a) ServiceWells (b) Drilling Wells (c)
--------------------- ----------------- ------------------
Gross Net Gross Net Gross Net
--------- --------- ------- -------- -------- --------
Crude Oil... 2,509 1,520 975 723 2 2
Natural Gas. 7 3 - - - -
--------- --------- ------- -------- -------- --------
Total Wells. 2,516 1,523 975 723 2 2
========= ========= ======= ======== ======== ========
___________
(a) Includes active wells and wells temporarily shut-in. As of December 31,
2004, we did not operate any gross wells with multiple completions.
(b) Consists of injection, water supply and disposal wells.
(c) Consists of development wells in the process of being drilled as of
December 31, 2004.
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The oil and gas producing fields in which we own interests are located in
the Permian Basin area of West Texas. The following table reflects our net
productive and dry wells that were completed in each of the three years ended
December 31, 2004, 2003 and 2002:
2004 2003 2002
------- ------ -------
Productive
Development....... 31 69 41
Exploratory....... - - -
Dry
Development....... - - -
Exploratory....... - - -
------- ------ -------
Total Wells........ 31 69 41
======= ====== =======
_________
Notes: The above table includes wells that were completed during each year
regardless of the year in which drilling was initiated, and does not
include any wells where drilling operations were not completed as of the
end of the applicable year. Also, the table includes our previous 15%
equity interest in MKM Partners, L.P. MKM Partners, L.P was dissolved on
June 30, 2003. Development wells include wells drilled in the proved area
of an oil or gas resevoir.
The following table reflects the developed and undeveloped oil and gas
acreage that we held as of December 31, 2004:
Gross Net
----------- -----------
Developed Acres..... 61,928 58,438
Undeveloped Acres... 7,839 7,227
----------- -----------
Total.............. 69,767 65,665
=========== ===========
See Note 19 to our consolidated financial statements included in this
report for additional information with respect to our oil and gas producing
activities.
Gas Plant Interests
We operate and own an approximate 22% working interest plus an additional
26% of the net profits of the Snyder gasoline plant, 51% of the Diamond M gas
plant and 100% of the North Snyder plant. The Snyder gasoline plant processes
gas produced from the SACROC unit and neighboring carbon dioxide projects,
specifically the Sharon Ridge and Cogdell units, all of which are located in the
Permian Basin area of West Texas. The Diamond M and the North Snyder plants
contract with the Snyder plant to process gas. Production of natural gas liquids
at the Snyder gasoline plant has increased from approximately 9,076 barrels per
day as of December 2003 to approximately 13,375 barrels per day as of December
2004.
Crude Oil Pipeline
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. The acquisition included a 450-mile crude oil pipeline system, consisting
of four mainline sections, numerous gathering systems and truck off-loading
stations. The mainline sections are all located within the State of Texas, and
the 20-inch diameter segment that runs from Wink to El Paso has a total capacity
of 115,000 barrels of crude oil per day.
As part of the transaction, we entered into a long-term throughput
agreement with Western Refining Company, L.P. to transport crude oil into
Western's 107,000 barrel per day refinery in El Paso. The acquisition allows us
to better manage crude oil deliveries from our oil field interests in West
Texas.
Terminals
Our Terminals segment includes the operations of our coal and dry-bulk
material services, including all transload, engineering and other in-plant
services, as well as all of the operations of our petroleum and
petrochemical-related liquids terminal facilities. Combined, the segment is
composed of approximately 75 owned or
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operated liquids and bulk terminal facilities, and more than 55 rail
transloading and materials handling facilities located throughout the United
States.
Our bulk terminal operations primarily involve bulk material handling
services; however, we also provide terminal engineering and design services and
in-plant services covering material handling, maintenance and repair services,
rail car switching services, ship agency and miscellaneous marine services. As
part of our bulk terminal operations, we own or operate 18 petroleum coke or
coal terminals in the United States. Petroleum coke is a by-product of the
refining process and has characteristics similar to coal. Petroleum coke supply
in the United States has increased in the last several years due to the
increased use of coking units by domestic refineries. Petroleum coke is used in
domestic utility and industrial steam generation facilities and is exported to
foreign markets. Most of our customers are large integrated oil companies that
choose to outsource the storage and loading of petroleum coke for a fee. In
2004, we handled approximately 6.5 million tons of petroleum coke and
approximately 27.2 million tons of coal. Combined, our dry-bulk and material
transloading facilities handled approximately 67.7 million tons of coal,
petroleum coke and other dry-bulk materials in 2004, and our transloading
operations handled approximately 75,000 rail cars.
Our liquids terminal operations primarily store refined petroleum products,
petrochemicals, industrial chemicals, and vegetable oil products, in aboveground
storage tanks and transfer products to and from pipelines, tank trucks, tank
barges, and tank rail cars. Combined, our liquids terminal facilities possess
liquids storage capacity of approximately 36.7 million barrels, and in 2004,
these terminals handled approximately 556 million barrels of clean petroleum,
petrochemical and vegetable oil products for approximately 250 different
customers.
We group our bulk and liquids terminal operations into nine regions. This
structure allows management to organize and evaluate segment performance and to
help make operating decisions and allocate resources. The following is a listing
of our nine regions and a summary of the competition faced by our Terminals
segment.
Terminals Segment - Regions
o Midwest o Northeast o Mid-Atlantic
o Southeast o Lower Mississippi River o Gulf Coast
o West Coast o Materials Services o Ferro Alloys
Midwest Region
o Argo o Chicago o Cincinnati River o Cincinnati Bulk
o Queen City o Dravosburg o Milwaukee o Dakota
o Pinney Dock o Owensboro Gateway o Evansville o Ghent
o Louisville o Nebraska City o Omaha o St. Joe
The Midwest region includes facilities that service industry in the Chicago
area and provide products to end-user markets in high population areas along the
Ohio River. The facilities handle a wide variety of liquid products, including
clean petroleum products, asphalt and residual oil, commodity chemicals, special
chemicals and food grade liquids. The services provided at these facilities
include receiving and discharging products via pipelines, vessels, tank cars and
tank trucks; storing productrs; transferring products; performing specialty
handling services (heating, cooling, nitrogen, etc.); and performing drumming
services.
The region includes two facilities in the Chicago area: one facility is in
Argo, Illinois, approximately 14 miles southwest of downtown Chicago. The other
facility is located in the Port of Chicago along the Calumet River. The Argo
facility is a large throughput fuel ethanol facility and a major break bulk
facility for large chemical manufacturers and distributors. It has approximately
2.4 million barrels of capacity in tankage ranging from 50,000 gallons to 80,000
barrels. The Argo terminal is situated along the Chicago sanitary and ship
channel, and has three barge docks. The facility is connected to TEPPCO and
Westshore pipelines, and has a direct connection to Midway Airport. The Canadian
National railroad services this facility. The Port of Chicago facility handles a
wide variety of liquids chemicals with a working capacity of approximately
741,000 barrels in tanks ranging from 12,000 gallons to 55,000 barrels. The
facility provides access to a full slate of transportation options, including a
deep water barge/ship berth on Lake Calumet, and offers services including truck
loading and off-loading, iso-container
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handling and drumming. There are two ship docks and four barge docks, and the
facility is served by the Norfolk Southern railroad.
The Midwest Region also includes two facilities along the Ohio River in
Cincinnati, Ohio. The total storage is approximately 905,000 barrels in tankage
ranging from 120 barrels to 96,000 barrels. There are three barge docks, and the
NNU and CSX railroads provide rail service. The facilities provide storage for
asphalt, heavy oils, and commodity and specialty chemicals. They also offer
warehouse services and serve dry bulk handling needs, including salt, coal, soda
ash, and agricultural commodities.
We also own a bulk terminal located in Dravosburg, Pennsylvania, just south
of Pittsburgh along the Monongahela River. There are approximately 242,000
barrels of storage in tanks ranging from 1,200 barrels to 38,000 barrels. There
are two barge docks and NS railroad provides rail service. The facility
primarily stores asphalt, distillates, wax and other commodities, and offers
handling services.
Our Midwest region also includes our Milwaukee and Dakota dry-bulk
commodity facilities, located in Milwaukee, Wisconsin and St. Paul, Minnesota,
respectively. The Milwaukee terminal is located on 34 acres of property leased
from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt.
The Dakota terminal is on 55 acres in St. Paul and primarily handles salt and
grain products. In the fourth quarter of 2004, we completed the construction of
a new cement loading facility at the Dakota terminal. The project's cost was
approximately $20 million, and the facility covers nearly nine acres and
includes an unloading system, seven storage silos, a loading and weighing
system, and electrical and compressed air systems to move the cement.
Included among the remaining Midwest terminals are our Pinney Dock and
Owensboro Gateway terminals. Our Pinney Dock terminal is located in Ashtabula,
Ohio along Lake Erie. It handles iron ore, titanium ore, magnetite and other
aggregates. Pinney Dock has six docks with 15,000 feet of vessel berthing space,
200 acres of outside storage space, 400,000 feet of warehouse space and two
45-ton gantry cranes. The Owensboro Gateway terminal, located near Owensboro,
Kentucky, is one of the nation's largest storage and handling points for bulk
aluminum. The facility also handles various other bulk materials, as well as a
barge scrapping facility.
As a result of our acquisition of Kinder Morgan River Terminals LLC,
formerly Global Material Services LLC, in October 2004, we added to our Midwest
network of terminals, acquiring terminals located in Evansville, Indiana; Ghent,
Kentucky; Louisville, Kentucky; Nebraska City, Nebraska; Omaha, Nebraska; and
St. Joseph, Missouri. These facilities handle a wide range of products including
steel, aluminum, scrap, grain, gypsum, coal, pig iron, fertilizer, silicon
metals, stainless slabs, iron, feeds, and lumber.
Northeast Region
o Carteret o Perth Amboy o Newark o Camden
The Northeast region services the northeastern part of the United States
from the Port of Philadelphia to the New York Harbor. The facilities in the
Northeast region handle a wide variety of liquids products ranging from
petroleum products to specialty chemicals. The services provided at these
facilities include storing products, and receiving and discharging products via
pipelines, vessels, tank cars, tank trucks and inter-modal transfers, utilizing
a wide array of automated systems for special product handling.
The region includes our two liquids facilities in the New York Harbor area:
one in Carteret, New Jersey and the other in Perth Amboy, New Jersey. The
Carteret facility is located along the Arthur Kill River just south of New York
City and has a capacity of approximately 7.7 million barrels of petroleum and
petrochemical products, of which 1.1 million barrels have been added since our
acquisition of the Carteret terminal in January 2001. In addition, in October
2003, we completed the construction of a new 16-inch diameter pipeline at
Carteret that connects to the Buckeye pipeline system, a major products pipeline
serving the East Coast. Our Carteret facility has two ship docks with a 37-foot
mean low water depth and four barge docks. It is connected to the Colonial,
Buckeye, Sun and Harbor pipeline systems, and the CSX and Norfolk Southern
railroads service the facility. The Perth Amboy facility is also located along
the Arthur Kill River and has a capacity of approximately 2.3 million barrels of
petroleum and petrochemical products. Tank sizes range from 2,000 barrels to
300,000 barrels. The Perth Amboy terminal provides chemical and petroleum
storage and handling, as well as dry-bulk handling of salt and aggregates.
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In addition to providing product movement via vessel, truck and rail, Perth
Amboy has direct access to the Buckeye and Colonial pipelines. The facility has
one ship dock and one barge dock, and is connected to the CSX and Norfolk
Southern railroads.
Our two New Jersey facilities offer a viable alternative for moving
petroleum products between the refineries and terminals throughout the New York
Harbor and both are New York Mercantile Exchange delivery points for gasoline
and heating oil. Both facilities are connected to the Intra Harbor Transfer
Service, an operation that offers direct outbound pipeline connections that
allow product to be moved from over 20 Harbor delivery points to destinations
north and west of New York City.
The Northeast region also includes the assets of our Port Newark bulk
terminal located at Port Newark, New Jersey and our Camden bulk terminal,
located along the Delaware River in Camden, New Jersey. Our Port Newark facility
offers almost 13 acres of outdoor storage for both de-icing and industrial salt,
vermiculite and other bulk products. Its assets include three floating cranes,
nine wheel loaders and three track bulldozers. The facility allows us to offer
ship, truck and rail storage, ship load out to trucks or rail, or truck and rail
load out to ships. Our Camden facility transfers scrap metal, vermiculite and
other mineral products.
Mid-Atlantic Region
o Pier IX o Shipyard River o Philadelphia o Chesapeake Bay
o Fairless Hills o Cora o Grand Rivers o North Charleston
This region includes our Pier IX Terminal located in Newport News,
Virginia. The terminal originally opened in 1983 and has the capacity to
transload approximately 12 million tons of coal annually. It can store 1.3
million tons of coal on its 30-acre storage site. For coal, the terminal offers
blending services and rail to storage or direct transfer to ship; for other dry
bulk products, the terminal offers ship to storage to rail or truck. In
addition, the Pier IX Terminal operates a cement facility, which has the
capacity to transload over 400,000 tons of cement annually. Since late 2002,
Pier IX has operated a synfuel plant on site, and in early 2004, Pier IX began
to operate a second synfuel plant on site. Volumes of synfuel produced in 2004
were 3.1 million tons. Our Pier IX Terminal exports coal to foreign markets,
serves power plants on the eastern seaboard of the United States, and imports
cement pursuant to a long-term contract. The Pier IX Terminal is served by the
CSX Railroad, which transports coal from central Appalachian and other eastern
coal basins. Cement imported to the Pier IX Terminal primarily originates in
Europe.
Also included in the Mid-Atlantic region is our Shipyard River Terminal,
located in Charleston, South Carolina. Shipyard is able to unload, store and
reload coal imported from various foreign countries. The imported coal is often
a cleaner-burning, low-sulfur coal and it is used by local utilities to comply
with the U.S. Clean Air Act. Shipyard River Terminal has the capacity to handle
approximately 2.5 million tons of coal and petroleum coke per year and offers
approximately 300,000 tons of total storage of which 50,000 tons are under roof.
Situated approximately four miles north of Shipyard, is our North
Charleston Terminal, which we acquired in April 2004. This facility sits on 30
acres of land and has the potential to handle dry bulk as well as liquids. In
aggregate terms, the facility can store 430,000 barrels of liquids in seven
tanks. Both CSX and NS have railroad service nearby.
Our Philadelphia, Pennsylvania liquids terminal is located on the Delaware
River and offers a storage capacity of over 1.2 million barrels. A variety of
tank system configurations are available including stainless steel and pressure
vessels for the storage of specialty chemicals. The storage and handling of
petroleum and petroleum based products are also strong components in
Philadelphia's base service.
Our Chesapeake Bay bulk terminal facility located at Sparrows Point,
Maryland, offers stevedoring services, storage, and rail, ground, or water
transportation for products such as coal, petroleum coke, iron and steel slag,
and other mineral products. It offers both warehouse and approximately 100 acres
of open storage.
Effective December 1, 2004, we acquired substantially all of the assets
used to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania. Opened in 1997 and
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recognized as a major steel distribution facility, the terminal is referred to
as our Kinder Morgan Fairless Hills Terminal. It is located on the bend of the
Delaware River below Trenton, New Jersey and is the largest port on the East
Coast for the handling of semi-finished steel slabs. The port operations at
Fairless Hills also include the handling of other types of steel and specialized
cargo that caters to the construction industry and service centers that use
steel sheet and plate. The port has four ship berths with a total length of
2,200 feet and a maximum draft of 38.5 feet. It contains two mobile harbor
cranes and is served by connections to two Class I rail lines: CSX and Norfolk
Southern.
The region also includes two large coal terminals: our Cora terminal and
our Grand Rivers terminal. Our Cora terminal is a high-speed, rail-to-barge coal
transfer and storage facility. Built in 1980, the terminal is located on
approximately 480 acres of land along the upper Mississippi River near Cora,
Illinois, about 80 miles south of St. Louis, Missouri. The terminal has a
throughput capacity of about 15 million tons per year and is currently equipped
to store up to one million tons of coal. This storage capacity provides
customers the flexibility to coordinate their supplies of coal with the demand
at power plants. Our Cora terminal sits on the mainline of the Union Pacific
Railroad and is strategically positioned to receive coal shipments from the
western United States.
Our Grand Rivers terminal is a coal transloading and storage facility
located along the Tennessee River just above the Kentucky Dam. The terminal is
operated on land under easements with an initial expiration of July 2014 and has
current annual throughput capacity of approximately 12 million tons with a
storage capacity of approximately one million tons. Grand Rivers provides easy
access to the Ohio-Mississippi River network and the Tennessee-Tombigbee River
system. The Paducah & Louisville Railroad, a short line railroad, serves Grand
Rivers with connections to seven Class I rail lines including the Union Pacific,
CSX, Illinois Central and Burlington Northern Santa Fe.
Our Cora and Grand Rivers terminals handle low sulfur coal originating in
Wyoming, Colorado, and Utah, as well as coal that originates in the mines of
southern Illinois and western Kentucky. However, since many shippers,
particularly in the East, are using western coal or a mixture of western coal
and other coals as a means of meeting environmental restrictions, we anticipate
that growth in volume through the terminals will be primarily due to increased
use of western low sulfur coal originating in Wyoming, Colorado and Utah. Coal
continues to be the fuel of choice for electric generation, accounting for more
than 50% of United States electric generation feedstock. Forecasts of overall
coal usage and power plant usage for the next 20 years show an increase of about
1.5% per year. Current domestic supplies are predicted to last for several
hundred years. Most coal transloaded through our coal terminals is destined for
use in coal-fired electric generation.
We believe that obligations to comply with the Clean Air Act Amendments of
1990 will cause shippers to increase the use of cleaner burning low sulfur coal
from the western United States and from foreign sources. Approximately 80% of
the coal loaded through our Cora and Grand Rivers terminals is low sulfur coal
originating from mines located in the western United States, including the Hanna
and Powder River basins in Wyoming, western Colorado and Utah. In 2004, four
major customers accounted for approximately 90% of all the coal loaded through
our Cora Terminal.
Southeast Region
o Tampaplex o Port Sutton o Port Manatee
o Hartford Street o Elizabeth River o Nassau
o Blackpoint
This region includes our Kinder Morgan Tampaplex terminal, a marine
terminal acquired in December 2003 and located in Tampa, Florida. The terminal
sits on a 114-acre site and serves as a storage and receipt point for imported
ammonia, as well as an export location for dry bulk products, including
fertilizer and animal feed. The terminal also includes an inland bulk storage
warehouse facility used for overflow cargoes from our Port Sutton import
terminal, which is also located in Tampa. Port Sutton sits on 16 acres of land
and offers 200,000 tons of covered storage. Primary products handled in 2004
included fertilizers, salt, ores, and liquid chemicals. Also in the Tampa Bay
area are our Port Manatee and Hartford Street terminals. Port Manatee has four
warehouses which can store 130,000 tons of bulk products. Products handled at
Port Manatee include fertilizers, ores and other general cargo. At our
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Hartford Street terminal, anhydrous ammonia and fertilizers are handled and
stored in two warehouses with an aggregate capacity of 23,000 net tons.
The Southeast region also includes our Elizabeth River bulk terminal,
located in Chesapeake, Virginia, and our Nassau bulk terminal, located in
Fernandina Beach, Florida. The Elizabeth River terminal offers over 500,000
square feet of covered storage and approximately ten acres of outdoor storage
for products such as fertilizers, ores and minerals and various feeds and
grains. Nassau offers approximately 180,000 square feet of warehouse storage and
ten acres of container yard storage, and provides stevedoring services and
containerized cargo services for various forest products.
Lower Mississippi River (Louisiana) Region
o Harvey o St. Gabriel o IMT o Gramercy
o Barge Canal Dock o BR Liquid Dock o Chalmette o Amory Bulk
o Belle Helene o Ft. Smith Warehouse o W. Memphis Reload o W. Memphis
Terminal
o Decatur o Vicksburg o Delisle o Ft. Smith
Terminal
o Globalplex o Great Lakes Carbon o Guntersville o Helena
o Memphis Terminal o Pine Bluff o Port Arthur o P.C.S.
The region consists of various bulk and liquid terminal facilities and
related assets located primarily on the southern edge of the lower Mississippi
River. These terminals serve customers in the alumina, cement, salt, soda ash,
ilmenite, fertilizer, ore and other industries seeking specialists who can
build, own and operate terminals.
Two of the region's largest liquids facilities in South Louisiana are: our
Port of New Orleans facility located in Harvey, Louisiana, and our St. Gabriel
terminal, located near a major petrochemical complex in Geismar, Louisiana. The
New Orleans facility handles a variety of liquids products such as chemicals,
vegetable oils, animal fats, alcohols and oil field products. It has
approximately three million barrels of total tanks ranging in sizes from 416
barrels to 200,000 barrels. There are three ship docks and one barge dock, and
the Union Pacific railroad provides rail service. The terminal can be accessed
by vessel, barge, tank truck, or rail, and also provides ancillary services
including drumming, packaging, warehousing, and cold storage services. Our St.
Gabriel facility is located approximately 75 miles north of the New Orleans
facility on the left descending bank of the Mississippi River near the town of
St. Gabriel, Louisiana. The facility has approximately 340,000 barrels of tank
capacity and the tanks vary in sizes ranging from 1,500 barrels to 80,000
barrels. There are three local pipeline connections at the facility which enable
the movement of products from the facility to the petrochemical plants in
Geismar, Louisiana.
The region also includes our 66 2/3% ownership interest in the
International Marine Terminals Partnership. IMT operates a bulk commodity
transfer terminal facility located in Port Sulphur, Louisiana. In 2004, the
facility handled approximately 11.9 million tons of iron ore, coal, petroleum
coke and barite. The Port Sulphur location is a multi-purpose import and export
facility that utilizes land and a dock facility. It contains storage capacity of
approximately 50 acres that can handle 1.3 million tons of coal and/or petroleum
coke. An additional 100 acres is currently undeveloped.
The Lower Mississippi Region also has in-plant operations, where we staff
and operate the loading and unloading equipment for specific customers. For
example, at our Chalmette, Louisiana facility, we load barges with petroleum
coke; at our Gramercy bulk terminal, located in Mt. Airy, Louisiana, we provide
rail switching services and we transfer alumina from railcars to barges.
Gulf Coast Region
o Pasadena o Galena Park
This region includes our Houston, Texas terminal complex, located in
Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a
distribution hub for Houston's refineries situated on or near the Houston Ship
Channel, the Pasadena and Galena Park terminals are the western Gulf Coast
refining community's central interchange point. The complex has approximately
17.7 million barrels of capacity and is connected via pipeline to 14 refineries,
four petrochemical plants and ten major outbound pipelines.
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Since our acquisition of the terminal complex in January 2001, we have
added more than one million barrels of new storage capacity, as refinery outputs
along the Gulf Coast have continued to increase. We have also upgraded our
pipeline manifold connection with the Colonial pipeline system, added pipeline
connections to new refineries and expanded our truck rack. In addition, the
facilities have four ship docks and seven barge docks for inbound and outbound
movement of products. The terminals are served by the Union Pacific railroad.
West Region
o Benicia o LAXT o Longview o Portland
o Vancouver
We own or operate five bulk terminals located primarily on the West Coast.
These terminals serve customers in the alumina, petroleum coke, salt, soda ash,
fertilizer, and other dry bulk product industries.
The West region includes our Portland Bulk Terminal #4 facility and our
Benicia Coke terminal. Portland Bulk Terminal #4 is located in Portland, Oregon
and exports approximately two million tons of soda ash per year to markets in
southeast Asia. It has an annual capacity of approximately 3.6 million tons. The
Benicia Coke terminal, located in Benicia, California, takes fluid bed green
petroleum coke from railcars to storage silos and from storage to ship. It has
an annual capacity of approximately 350,000 tons.
Also included in the West region is the Los Angeles Export Terminal, where
operations primary consist of loading vessels carrying coal and petroleum coke.
LAXT, which is served by the Union Pacific railroad, has two million tons of
outdoor storage space and 100,000 tons of covered storage space.
Materials Services (rail transloading) Region
o Transloading (55) o Brooklyn Junction o Moundsville o New Johnsonville
This region primarily includes the rail-transloading operations owned by
Kinder Morgan Materials Services LLC, referred to in this report as KMMS. KMMS
operates approximately 55 rail transloading facilities, of which 47 are located
east of the Mississippi River. The CSX, Norfolk Southern, Union Pacific, Kansas
City Southern and A&W railroads provide rail service for these terminal
facilities. Approximately 50% of the products handled by KMMS are liquids,
including an entire spectrum of liquid chemicals, and 50% are dry bulk products.
Many of the facilities are equipped for bi-modal operation (rail-to-truck, and
truck-to-rail). KMMS also designs and builds transloading facilities, performs
inventory management services, and provides value-added services such as
blending, heating and sparging.
Ferro Alloys Region
o Chicago o Decatur o Houston
o Industry o Mingo Junction o Netherlands
The terminal operations included in our Ferro Alloys region were acquired
as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004.
The region includes six terminal facilities or locations that specialize in the
handling of ferro alloys, pig iron and other bulk supplies for the metals
industries. Each terminal provides general commodity or alloy services as needed
by local markets.
Engineering and Other
This segment includes the engineering operations of RCI Holdings, Inc., a
major engineering and construction management company. RCI is a wholly-owned
subsidiary that specializes in providing design and construction services for
dry bulk material handling terminals. Their offices are located in Metairie,
Louisiana, and Columbus, Ohio.
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Competition
We are one of the largest independent operators of liquids and bulk
terminals in North America. Our primary competitors are Magellan, Kaneb, IMTT,
Vopak, Oil Tanking, TransMontaigne, and Savage Industries.
Our petroleum coke and other bulk terminals compete with numerous
independent terminal operators, other terminals owned by oil companies and other
industrials opting not to outsource terminal services. Many of our other bulk
terminals were constructed pursuant to long-term contracts for specific
customers. As a result, we believe other terminal operators would face a
significant disadvantage in competing for this business.
Two new coal terminals that compete with our Cora terminal and our Grand
Rivers terminal were completed in 2003. While our Cora and Grand Rivers
terminals are modern high capacity coal terminals, in 2004, some volume was
diverted to the new terminals by the Tennessee Valley Authority in order to
promote increased competition. Our Pier IX terminal competes primarily with two
modern coal terminals located in the same Virginian port complex as our Pier IX
terminal.
Major Customers
Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2004, 2003 and 2002, only one customer
accounted for more than 10% of our total consolidated revenues. Total
transactions with CenterPoint Energy accounted for 14.3% of our total
consolidated revenues during 2004, 16.8% of our total consolidated revenues
during 2003 and 15.6% of our total consolidated revenues during 2002. The high
percentage of our total revenues attributable to CenterPoint Energy directly
relates to the growth of our Natural Gas Pipelines segment, especially since our
acquisition of Kinder Morgan Tejas on January 31, 2002. Due to this acquisition
and the subsequent formation of our Texas intrastate natural gas group, we have
realized significant increases in the volumes of natural gas we buy and sell
within the State of Texas. As a result, both our total consolidated revenues and
our total consolidated purchases (cost of sales) have increased considerably
since the beginning of 2002 due to the inclusion of the cost of gas in both
financial statement line items. These higher revenues and higher purchased gas
cost do not necessarily translate into increased margins in comparison to those
situations in which we charge to transport gas owned by others. We do not
believe that a loss of revenues from any single customer would have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Regulation
Interstate Common Carrier Regulation
Some of our pipelines are interstate common carrier pipelines, subject to
regulation by the Federal Energy Regulatory Commission under the Interstate
Commerce Act. The ICA requires that we maintain our tariffs on file with the
FERC, which tariffs set forth the rates we charge for providing transportation
services on our interstate common carrier pipelines as well as the rules and
regulations governing these services. Petroleum products pipelines may change
their rates within prescribed ceiling levels that are tied to an inflation
index. Shippers may protest rate increases made within the ceiling levels, but
such protests must show that the portion of the rate increase resulting from
application of the index is substantially in excess of the pipeline's increase
in costs from the previous year. A pipeline must, as a general rule, utilize the
indexing methodology to change its rates. The FERC, however, uses
cost-of-service ratemaking, market-based rates and settlement rates as
alternatives to the indexing approach in certain specified circumstances.
During the first quarter of 2003, the FERC made a significant positive
adjustment to the index which petroleum products pipelines use to adjust their
regulated tariffs for inflation. The old index used percent growth in the
producer price index for finished goods, and then subtracted one percent. The
new index eliminated the one percent reduction. As a result, we filed for
indexed rate adjustments on a number of our petroleum products pipelines and
realized benefits from the new index beginning in the second quarter of 2003.
Rate adjustments pursuant to the index were made on a number of pipeline systems
in 2004.
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The ICA requires, among other things, that such rates on interstate common
carrier pipelines be "just and reasonable" and nondiscriminatory. The ICA
permits interested persons to challenge newly proposed or changed rates and
authorizes the FERC to suspend the effectiveness of such rates for a period of
up to seven months and to investigate such rates. If, upon completion of an
investigation, the FERC finds that the new or changed rate is unlawful, it is
authorized to require the carrier to refund the revenues in excess of the prior
tariff collected during the pendency of the investigation. The FERC may also
investigate, upon complaint or on its own motion, rates that are already in
effect and may order a carrier to change its rates prospectively. Upon an
appropriate showing, a shipper may obtain reparations for damages sustained
during the two years prior to the filing of a complaint.
On October 24, 1992, Congress passed the Energy Policy Act of 1992. The
Energy Policy Act deemed petroleum products pipeline tariff rates that were
in
effect for the 365-day period ending on the date of enactment or that were in
effect on the 365th day preceding enactment and had not been subject to
complaint, protest or investigation during the 365-day period to be just and
reasonable or "grandfathered" under the ICA. The Energy Policy Act also limited
the circumstances under which a complaint can be made against such grandfathered
rates. The rates we charge for transportation service on our North System and
Cypress Pipeline were not suspended or subject to protest or complaint during
the relevant 365-day period established by the Energy Policy Act. For this
reason, we believe these rates should be grandfathered under the Energy Policy
Act. Certain rates on our Pacific operations' pipeline system were subject to
protest during the 365-day period established by the Energy Policy Act.
Accordingly, certain of the Pacific pipelines' rates have been, and continue to
be, subject to complaints with the FERC, as is more fully described in Note 16
to our consolidated financial statements included elsewhere in this report.
Both the performance of and rates charged by companies performing
interstate natural gas transportation and storage services are regulated by the
FERC under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy
Act.
Beginning in the mid-1980's, the FERC initiated a number of regulatory
changes intended to create a more competitive environment in the natural gas
marketplace. Among the most important of these changes were:
o Order No. 436 (1985) requiring open-access, nondiscriminatory
transportation of natural gas;
o Order No. 497 (1988) which set forth new standards and guidelines
imposing certain constraints on the interaction between interstate
natural gas pipelines and their marketing affiliates and imposing
certain disclosure requirements regarding that interaction; and
o Order No. 636 (1992) which required interstate natural gas pipelines
that perform open-access transportation under blanket certificates to
"unbundle" or separate their traditional merchant sales services from
their transportation and storage services and to provide comparable
transportation and storage services with respect to all natural gas
supplies whether purchased from the pipeline or from other merchants
such as marketers or producers.
Natural gas pipelines must now separately state the applicable rates for
each unbundled service they provide (i.e., for the natural gas commodity,
transportation and storage). Order 636 contains a number of procedures designed
to increase competition in the interstate natural gas industry, including:
o requiring the unbundling of sales services from other services;
o permitting holders of firm capacity on interstate natural gas
pipelines to release all or a part of their capacity for resale by the
pipeline; and
o the issuance of blanket sales certificates to interstate pipelines for
unbundled services.
Order 636 has been affirmed in all material respects upon judicial review,
and our own FERC orders approving our unbundling plans are final and not subject
to any pending judicial review.
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On November 25, 2003, the Federal Energy Regulatory Commission issued Order
No. 2004, adopting revised Standards of Conduct that apply uniformly to
interstate natural gas pipelines and public utilities. In light of the changing
structure of the energy industry, these Standards of Conduct govern
relationships between regulated interstate natural gas pipelines and all of
their energy affiliates. These new Standards of Conduct were designed to
eliminate the loophole in the previous regulations that did not cover an
interstate natural gas pipeline's relationship with energy affiliates that are
not marketers. The rule is designed to prevent interstate natural gas pipelines
from giving an undue preference to any of their energy affiliates and to ensure
that transmission is provided on a nondiscriminatory basis. In addition, unlike
the prior regulations, these requirements apply even if the energy affiliate is
not a customer of its affiliated interstate pipeline. The effective date of
Order No. 2004 was September 22, 2004. Our interstate natural gas pipelines have
implemented compliance with these Standards of Conduct. Please refer to Note 16
to our consolidated financial statements included elsewhere in this report for
additional information regarding FERC Order No. 2004 and other Standards of
Conduct Rulemaking.
California Public Utilities Commission
The intrastate common carrier operations of our Pacific operations'
pipelines in California are subject to regulation by the California Public
Utilities Commission under a "depreciated book plant" methodology, which is
based on an original cost measure of investment. Intrastate tariffs filed by us
with the CPUC have been established on the basis of revenues, expenses and
investments allocated as applicable to the California intrastate portion of our
Pacific operations' business. Tariff rates with respect to intrastate pipeline
service in California are subject to challenge by complaint by interested
parties or by independent action of the CPUC. A variety of factors can affect
the rates of return permitted by the CPUC, and certain other issues similar to
those which have arisen with respect to our FERC regulated rates could also
arise with respect to our intrastate rates. Certain of our Pacific operations'
pipeline rates have been, and continue to be, subject to complaints with the
CPUC, as is more fully described in Note 16 to our consolidated financial
statements.
Safety Regulation
Our interstate pipelines are subject to regulation by the United States
Department of Transportation and our intrastate pipelines and other operations
are subject to comparable state regulations with respect to their design,
installation, testing, construction, operation, replacement and management. We
must permit access to and copying of records, and make certain reports and
provide information as required by the Secretary of Transportation. Comparable
regulation exists in some states in which we conduct pipeline operations. In
addition, our truck and terminal loading facilities are subject to U.S. DOT
regulations dealing with the transportation of hazardous materials by motor
vehicles and rail cars. We believe that we are in substantial compliance with
U.S. DOT and comparable state regulations.
The Pipeline Safety Improvement Act of 2002 was signed into law on December
17, 2002, governing the areas of testing, education, training and communication.
The Act requires pipeline companies to perform integrity tests on natural gas
transmission pipelines that exist in high population density areas that are
designated as High Consequence Areas. Pipeline companies are required to perform
the integrity tests within ten years of the date of enactment and must perform
subsequent integrity tests on a seven year cycle. At least 50% of the highest
risk segments must be tested within five years of the enactment date. The risk
ratings are based on numerous factors, including the population density in the
geographic regions served by a particular pipeline, as well as the age and
condition of the pipeline and its protective coating. Testing consists of
hydrostatic testing, internal electronic testing, or direct assessment of the
piping. In addition to the pipeline integrity tests, pipeline companies must
implement a qualification program to make certain that employees are properly
trained, and the U.S. DOT has approved our qualification program. We believe
that we are in substantial compliance with this law's requirements and have
integrated appropriate aspects of this pipeline safety law into our Operator
Qualification Program, which is already in place and functioning. A similar
integrity management rule for refined petroleum products pipelines became
effective May 29, 2001. All baseline assessments for products pipelines must be
completed by March 31, 2008.
Certain of our products pipelines and natural gas pipelines have been
issued orders and civil penalties by the U.S. DOT's Office of Pipeline Safety
concerning alleged violations of certain federal regulations concerning our
pipeline Integrity Management Program. However, we dispute some of the findings,
disagree that civil penalties are
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appropriate for them, and have requested an administrative hearing on these
matters according to the U.S. DOT regulations. Information on these matters is
more fully described in Note 16 to our consolidated financial statements.
On March 25, 2003, the U.S. DOT issued their final rules on Hazardous
Materials: Security Requirements for Offerors and Transporters of Hazardous
Materials. We believe that we are in substantial compliance with these rules and
have made revisions to our Facility Security Plan to remain consistent with the
requirements of these rules.
We are also subject to the requirements of the Federal Occupational Safety
and Health Act and other comparable federal and state statutes. We believe that
we are in substantial compliance with Federal OSHA requirements, including
general industry standards, recordkeeping requirements and monitoring of
occupational exposure to hazardous substances.
In general, we expect to increase expenditures in the future to comply with
higher industry and regulatory safety standards. Some of these changes, such as
U.S. DOT implementation of additional hydrostatic testing requirements, could
significantly increase the amount of these expenditures. Such expenditures
cannot be accurately estimated at this time.
State and Local Regulation
Our activities are subject to various state and local laws and regulations,
as well as orders of regulatory bodies, governing a wide variety of matters,
including:
o marketing;
o production;
o pricing;
o pollution;
o protection of the environment; and
o safety.
Environmental Matters
Our operations are subject to federal, state and local, and some foreign
laws and regulations governing the release of regulated materials into the
environment or otherwise relating to environmental protection or human health or
safety. We believe that our operations are in substantial compliance with
applicable environmental laws and regulations. Any failure to comply with these
laws and regulations may result in the assessment of administrative, civil and
criminal penalties, imposition of remedial requirements, issuance of injunction
as to future compliance or other mandatory or consensual measures. We have an
ongoing environmental compliance program. However, risks of accidental leaks or
spills are associated with the transportation and storage of natural gas
liquids, refined petroleum products, natural gas and carbon dioxide, the
handling and storage of liquid and bulk materials and the other activities
conducted by us. There can be no assurance that we will not incur significant
costs and liabilities relating to claims for damages to property, the
environment, natural resources, or persons resulting from the operation of our
businesses. Moreover, it is possible that other developments, such as
increasingly strict environmental laws and regulations and enforcement policies
thereunder, could result in increased costs and liabilities to us.
Environmental laws and regulations have changed substantially and rapidly
over the last 35 years, and we anticipate that there will be continuing changes.
One trend in environmental regulation is to increase reporting obligations and
place more restrictions and limitations on activities, such as emissions of
pollutants, generation and disposal of wastes and use, storage and handling of
chemical substances that may impact human health and safety or the environment.
Increasingly strict environmental restrictions and limitations have resulted in
increased operating costs for us and other similar businesses throughout the
United States. It is possible that the costs of compliance
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with environmental laws and regulations may continue to increase. We will
attempt to anticipate future regulatory requirements that might be imposed and
to plan accordingly, but there can be no assurance that we will identify and
properly anticipate each such charge, or that our efforts will prevent material
costs, if any, from arising.
We are currently involved in environmentally related legal proceedings and
clean up activities. Although no assurance can be given, we believe that the
ultimate resolution of all these environmental matters will not have a material
adverse effect on our business, financial position or results of operations. We
have accrued an environmental reserve in the amount of $40.9 million as of
December 31, 2004. Our reserve estimates range in value from approximately $40.9
million to approximately $77.6 million, and we have recorded a liability equal
to the low end of the range. For additional information related to environmental
matters, see Note 16 to our consolidated financial statements included elsewhere
in this report.
Solid Waste
We own numerous properties that have been used for many years for the
production of crude oil, natural gas and carbon dioxide, the transportation and
storage of refined petroleum products and natural gas liquids and the handling
and storage of coal and other liquid and bulk materials. Virtually all of these
properties were owned by others before us. Solid waste disposal practices within
the petroleum industry have changed over the years with the passage and
implementation of various environmental laws and regulations. Hydrocarbons and
other solid wastes may have been disposed of in, on or under various properties
owned by us during the operating history of the facilities located on such
properties. Virtuallly all of these properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or other solid
wastes was not under our control. In such cases, hydrocarbons and other solid
wastes could migrate from the facilities and have an adverse effect on soils and
groundwater. We maintain a reserve to account for the costs of cleanup at sites
known to have surface or subsurface contamination requiring response action.
We generate both hazardous and nonhazardous solid wastes that are subject
to the requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes. From time to time, state regulators and the United
States Environmental Protection Agency consider the adoption of stricter
disposal standards for nonhazardous waste. Furthermore, it is possible that some
wastes that are currently classified as nonhazardous, which could include wastes
currently generated during pipeline or liquids or bulk terminal operations, may
in the future be designated as "hazardous wastes." Hazardous wastes are subject
to more rigorous and costly disposal requirements than nonhazardous wastes. Such
changes in the regulations may result in additional capital expenditures or
operating expenses for us.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as the "Superfund" law or "CERCLA," and analogous state laws, impose
joint and several liability, without regard to fault or the legality of the
original conduct, on certain classes of "potentially responsible persons" for
releases of "hazardous substances" into the environment. These persons include
the owner or operator of a site and companies that disposed of or arranged for
the disposal of the hazardous substances found at the site. CERCLA authorizes
the U.S. EPA and, in some cases, third parties to take actions in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs they incur, in addition to compensation
for natural resource damages, if any. Although "petroleum" is excluded from
CERCLA's definition of a "hazardous substance," in the course of our ordinary
operations, we have and will generate materials that may fall within the
definition of "hazardous substance." By operation of law, if we are determined
to be a potentially responsible person, we may be responsible under CERCLA for
all or part of the costs required to clean up sites at which such materials are
present, in addition to compensation for natural resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act and analogous state
statutes. We believe that the operations of our pipelines, storage facilities
and terminals are in substantial compliance with such statutes.
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Numerous amendments to the Clean Air Act were adopted in 1990. These
amendments contain lengthy, complex provisions that may result in the imposition
over the next several years of certain pollution control requirements with
respect to air emissions from the operations of our pipelines, treating
facilities, storage facilities and terminals. Depending on the nature of those
requirements and any additional requirements that may be imposed by state and
local regulatory authorities, we may be required to incur certain capital
expenditures over the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals and
addressing other air emission-related issues.
Due to the broad scope and complexity of the issues involved and the
resultant complexity and nature of the regulations, full development and
implementation of many Clean Air Act regulations have been delayed. Until such
time as the new Clean Air Act requirements are implemented, we are unable to
fully estimate the effect on earnings or operations or the amount and timing of
such required capital expenditures. At this time, however, we do not believe
that we will be materially adversely affected by any such requirements.
Clean Water Act
Our operations can result in the discharge of pollutants. The Federal Water
Pollution Control Act of 1972, as amended, also known as the Clean Water Act,
and analogous state laws impose restrictions and controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by applicable federal or state
authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of
the Clean Water Act as they pertain to prevention and response to oil spills.
Spill prevention control and countermeasure requirements of the Clean Water Act
and some state laws require diking and similar structures to help prevent
contamination of navigable waters in the event of an overflow or release. We
believe we are in substantial compliance with these laws.
EPA Fuel Specifications/Gasoline Volatility Restrictions
In order to control air pollution in the United States, the U.S. EPA has
adopted regulations that require the vapor pressure of motor gasoline sold in
the United States to be reduced from May through mid-September of each year.
These regulations mandated vapor pressure reductions beginning in 1989, with
more stringent restrictions beginning in 1992. States may impose additional
volatility restrictions. The regulations have had a substantial effect on the
market price and demand for normal butane, and to some extent isobutane, in the
United States. Gasoline manufacturers use butanes in the production of motor
gasolines. Since normal butane is highly volatile, it is now less desirable for
use in blended gasolines sold during the summer months. Although the U.S. EPA
regulations have reduced demand and may have contributed to a significant
decrease in prices for normal butane, low normal butane prices have not impacted
our pipeline business in the same way they would impact a business with
commodity price risk. The U.S. EPA regulations have presented the opportunity
for additional transportation services on portions of our liquid pipeline
systems, for example, our North System. In the summer of 1991, our North System
began long-haul transportation of refinery grade normal butane produced in the
Chicago area to the Bushton, Kansas area for storage and subsequent
transportation north from Bushton during the winter gasoline blending season.
That service continues, and we also provide transportation and storage of butane
from the Chicago area back to Bushton during the summer season.
Methyl Tertiary-Butyl Ether
Methyl tertiary-butyl ether (MTBE) is used as an additive in gasoline. It
is manufactured by chemically combining a portion of petrochemical production
with purchased methanol. Due to environmental and health concerns, California
mandated the elimination of MTBE from gasoline by January 1, 2004. Furthermore,
both the United States House of Representatives and the United States Senate
have introduced legislation that would gradually phase out the use of MTBE as a
gasoline blendstock and bar the use of MTBE within four years of enactment. We
cannot provide assurances regarding the likelihood of the passage of such
legislation.
In California, MTBE-blended gasoline has been replaced by an ethanol blend.
However, ethanol cannot be shipped through pipelines and therefore, we have
realized some reduction in California gasoline volumes transported by our
Pacific operations' pipelines. However, the conversion from MTBE to ethanol in
California has resulted in
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an increase in ethanol blending services at many of our refined petroleum
product terminal facilities, and the fees we earn for new ethanol-related
services at our terminals more than offsets the reduction in pipeline
transportation fees. Furthermore, we have aggressively pursued additional
ethanol opportunities.
Our role in conjunction with ethanol is proving beneficial to our various
business segments as follows:
o our Products Pipelines' terminals are blending ethanol because unlike
MTBE, it cannot flow through pipelines;
o our Natural Gas Pipelines segment is delivering natural gas through
our pipelines to service new ethanol plants that are being constructed
in the Midwest (natural gas is the feedstock for ethanol plants); and
o our Terminals segment is entering into liquid storage agreements for
ethanol around the country, in such areas as Houston, Nebraska and on
the East Coast.
Risk Factors
Like all businesses, we face various obstacles, including escalating
employee health and benefit costs, environmental issues and rising legal fees.
Regulatory challenges to our pipeline transportation rates, including the
current case involving our Pacific operations' pipelines, and possible policy
changes and/or reparation and refund payments ordered by governmental regulatory
entities could negatively affect our future financial performance.
Further, we are well-aware of the general uncertainty associated with the
current world economic and political environments in which we exist and we
recognize that we are not immune to the fact that our financial performance is
impacted by overall marketplace spending and demand. We are continuing to assess
the effect that terrorism would have on our businesses and in response, we have
increased security at our assets. Recent federal legislation provides an
insurance framework that should cause current insurers to continue to provide
sabotage and terrorism coverage under standard property insurance policies.
Nonetheless, there is no assurance that adequate sabotage and terrorism
insurance will be available at reasonable rates throughout 2005. Currently, we
do not believe that the increased cost associated with these measures will have
a material effect on our operating results.
Some of our specifically identified risk factors are as follows:
Pending Federal Energy Regulatory Commission and California Public
Utilities Commission proceedings seek substantial refunds and reductions in
tariff rates on some of our pipelines. If the proceedings are determined
adversely, they could have a material adverse impact on us. Regulators and
shippers on our pipelines have rights to challenge the rates we charge under
certain circumstances prescribed by applicable regulations. Some shippers on our
pipelines have filed complaints with the Federal Energy Regulatory Commission
and California Public Utilities Commission that seek substantial refunds for
alleged overcharges during the years in question and prospective reductions in
the tariff rates on our Pacific operations' pipeline system.
The FERC complaints, separately docketed in two different proceedings,
predominantly attacked the interstate pipeline tariff rates of our Pacific
operations' pipeline system, contending that the rates were not just and
reasonable under the Interstate Commerce Act and should not be entitled to
"grandfathered" status under the Energy Policy Act. Hearings on the second of
these two proceedings began in October 2001.
On June 24, 2003, a non-binding, phase one initial decision was issued by
an administrative law judge hearing a FERC case on the rates charged by our
Pacific operations' interstate portion of its pipelines. In his phase one
initial decision, the administrative law judge recommended that the FERC
"ungrandfather" our Pacific operations' interstate rates and found most of our
Pacific operations' rates at issue to be unjust and unreasonable. On March 26,
2004, the FERC issued an order on the phase one initial decision that reversed
the initial decision by finding that our Pacific operations' rates for its North
and Oregon Lines should remain "grandfathered" and amended the initial decision
by finding that SFPP's West Line rates (i) to Yuma and Tucson, Arizona and to
our CALNEV Pipeline, as of 1995, and (ii) to Phoenix, Arizona, as of 1997,
should no longer be "grandfathered" and are not just and reasonable. If these
rates are "ungrandfathered," they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods.
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On September 9, 2004, a non-binding, phase two initial decision was issued
by an administrative law judge hearing the FERC case on the rates charged by our
Pacific operations' interstate portion of its pipelines. If affirmed by the
FERC, the phase two initial decision would establish the basis for prospective
rates and the calculation of reparations for complaining shippers with respect
to our Pacific operations' West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision has no force or effect and
must be fully reviewed by the FERC, which may accept, reject or modify the
decision. A FERC order on phase two of the case is not expected before the third
quarter of 2005. Furthermore, any such order may be subject to further FERC
review, review by the United States Court of Appeals for the District of
Columbia Circuit, or both.
We estimated, as of December 31, 2003, that shippers' claims for
reparations totaled approximately $154 million and that prospective rate
reductions would have an aggregate average annual impact of approximately $45
million. As the timing for implementation of rate reductions and the payment of
reparations is extended, total estimated reparations and the interest accruing
on the reparations increase. For each calendar quarter of delay in the
implementation of rate reductions sought, we estimate that reparations and
accrued interest accumulates by approximately $9 million. We now assume that any
potential rate reductions will be implemented no earlier than the third quarter
of 2005 and that reparations and accrued interest thereon will be paid no
earlier than the third quarter of 2006; however, the timing, and nature, of any
rate reductions and reparations that may be ordered will likely be affected by
the FERC's income tax allowance inquiry in Docket No. PL05-5 and the FERC's
disposition of issues remanded by the D.C. Circuit in the BP West Coast
decision. If the phase two initial decision were to be largely adopted by the
FERC, the estimated reparations and rate reductions would be larger than noted
above; however, we continue to estimate the combined annual impact of the rate
reductions and the capital costs associated with financing the payment of
reparations sought by shippers and accrued interest thereon to be approximately
15 cents of distributable cash flow per unit. We believe, however, that the
ultimate resolution of these complaints will be for amounts substantially less
than the amounts sought. For more information on our Pacific operations'
regulatory proceedings, see Note 16 to our consolidated financial statements
included elsewhere in this report.
The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through our Pacific
operations' pipeline system in California. After the CPUC dismissed the initial
complaint and subsequently granted a limited rehearing on April 10, 2000, the
complainants filed a new complaint with the CPUC asserting the intrastate rates
were not just and reasonable.
Proposed rulemaking by the Federal Energy Regulatory Commission or other
regulatory agencies having jurisdiction could adversely impact our income and
operations. New laws or regulations or different interpretations of existing
laws or regulations applicable to our assets could have a negative impact on our
business, financial condition and results of operations.
Increased regulatory requirements relating to the integrity of our
pipelines will require us to spend additional money to comply with these
requirements. Through our regulated pipeline subsidiaries, we are subject to
extensive laws and regulations related to pipeline integrity. For example,
federal legislation signed into law in December 2002 includes guidelines for the
U.S. DOT and pipeline companies in the areas of testing, education, training and
communication. Compliance with existing and recently enacted regulations
requires significant expenditures. Additional laws and regulations that may be
enacted in the future, such as U.S. DOT implementation of additional hydrostatic
testing requirements, could significantly increase the amount of these
expenditures.
Our rapid growth may cause difficulties integrating new operations, and we
may not be able to achieve the expected benefits from any future acquisitions.
Part of our business strategy includes acquiring additional businesses that will
allow us to increase distributions to our unitholders. If we do not successfully
integrate acquisitions, we may not realize anticipated operating advantages and
cost savings. The integration of companies that have previously operated
separately involves a number of risks, including:
o demands on management related to the increase in our size after an
acquisition;
o the diversion of our management's attention from the management of
daily operations;
o difficulties in implementing or unanticipated costs of accounting,
estimating, reporting and other systems;
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o difficulties in the assimilation and retention of employees; and
o potential adverse effects on operating results.
We may not be able to maintain the levels of operating efficiency that
acquired companies have achieved or might achieve separately. Successful
integration of each of their operations will depend upon our ability to manage
those operations and to eliminate redundant and excess costs. Because of
difficulties in combining operations, we may not be able to achieve the cost
savings and other size-related benefits that we hoped to achieve after these
acquisitions, which would harm our financial condition and results of
operations.
Our acquisition strategy requires access to new capital. Tightened credit
markets or more expensive capital would impair our ability to grow. Part of our
business strategy includes acquiring additional businesses that will allow us to
increase distributions to our unitholders. During the period from December 31,
1996 to December 31, 2004, we made a significant number of acquisitions that
increased our asset base over 34 times and increased our net income over 69
times. We regularly consider and enter into discussions regarding potential
acquisitions and are currently contemplating potential acquisitions. These
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets and operations. We may need
new capital to finance these acquisitions. Limitations on our access to capital
will impair our ability to execute this strategy. We normally fund acquisitions
with short term debt and repay such debt through equity and long-term debt
offerings. An inability to access the capital markets may result in a
substantial increase in our leverage and have a detrimental impact on our credit
profile.
One of the factors that increases our attractiveness to investors, and as a
result may make it easier for us to access the capital markets, is the fact that
distributions to our partners are not subject to the double taxation that
shareholders in corporations may experience with respect to dividends that they
receive. The Jobs and Growth Tax Relief Reconciliation Act of 2003 generally
reduced the maximum tax rate on dividends paid by corporations to individuals to
15% in 2003 and, for taxpayers in the 10% and 15% ordinary income tax brackets,
to 5% in 2003 through 2007 and to zero in 2008. This legislation also reduced
the maximum tax rate for an individual to 35% and the maximum tax rate
applicable to net long term capital gains of an individual to 15%. This
legislation may cause some investments in corporations to be more attractive to
individual investors than they used to be when compared to an investment in
partnerships, thereby exerting downward pressure on the market price of our
common units and potentially making it more difficult for us to access the
capital markets.
Environmental regulation could result in increased operating and capital
costs for us. Our business operations are subject to federal, state and local
laws and regulations relating to environmental protection. If an accidental
leak, release or spill of liquid petroleum products, chemicals or other products
occurs from our pipelines or at our storage facilities, we may have to pay a
significant amount to clean up the leak, release or spill or pay for government
penalties, liability to government agencies for natural resource damage,
personal injury or property damage to private parties or significant business
interruption. The resulting costs and liabilities could negatively affect our
level of cash flow. In addition, emission controls required under the Federal
Clean Air Act and other similar federal and state laws could require significant
capital expenditures at our facilities. The impact on us of Environmental
Protection Agency standards or future environmental measures could increase our
costs significantly if environmental laws and regulations become stricter. In
addition, our oil and gas exploration and production activities are subject to
certain federal, state and local laws and regulations relating to environmental
quality and pollution control. These laws and regulations increase the costs of
these activities and may prevent or delay the commencement or continuance of a
given operation. Specifically, we are subject to laws and regulations regarding
the acquisition of permits before drilling, restrictions on drilling activities
in restricted areas, emissions into the environment, water discharges, and
storage and disposition of hazardous wastes. In addition, legislation has been
enacted which requires well and facility sites to be abandoned and reclaimed to
the satisfaction of state authorities. The costs of environmental regulation are
already significant, and additional or more stringent regulation could increase
these costs or could otherwise negatively affect our business.
Our future success depends in part upon our ability to develop additional
oil and gas reserves that are economically recoverable. The rate of production
from oil and natural gas properties declines as reserves are depleted. Without
successful development activities, the reserves and revenues of our CO2 business
segment will
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decline. We may not be able to develop or acquire additional reserves at an
acceptable cost or have necessary financing for these activities in the future.
The development of oil and gas properties involves risks that may result in
a total loss of investment. The business of developing and operating oil and gas
properties involves a high degree of business and financial risk that even a
combination of experience, knowledge and careful evaluation may not be able to
overcome. Acquisition and completion decisions generally are based on subjective
judgments and assumptions that are speculative. It is impossible to predict with
certainty the production potential of a particular property or well.
Furthermore, a successful completion of a well does not ensure a profitable
return on the investment. A variety of geological, operational, or
market-related factors, including, but not limited to, unusual or unexpected
geological formations, pressures, equipment failures or accidents, fires,
explosions, blowouts, cratering, pollution and other environmental risks,
shortages or delays in the availability of drilling rigs and the delivery of
equipment, loss of circulation of drilling fluids or other conditions may
substantially delay or prevent completion of any well, or otherwise prevent a
property or well from being profitable. A productive well may become uneconomic
in the event water or other deleterious substances are encountered, which impair
or prevent the production of oil and/or gas from the well. In addition,
production from any well may be unmarketable if it is contaminated with water or
other deleterious substances.
The volatility of natural gas and oil prices could have a material adverse
effect on our business. The revenues, profitability and future growth of our CO2
business segment and the carrying value of our oil and gas properties depend to
a large degree on prevailing oil and gas prices. Prices for oil and gas are
subject to large fluctuations in response to relatively minor changes in the
supply and demand for oil and gas, uncertainties within the market and a variety
of other factors beyond our control. These factors include, weather conditions
in the United States; the condition of the United States economy; the activities
of the Organization of Petroleum Exporting Countries; governmental regulation;
political stability in the Middle East and elsewhere; the foreign supply of oil
and gas; the price of foreign imports; and the availability of alternative fuel
sources.
A sharp decline in the price of natural gas or oil prices would result in a
commensurate reduction in our revenues, income and cash flows from the
production of oil and gas and could have a material adverse effect on the
carrying value of our proved reserves. In the event prices fall substantially,
we may not be able to realize a profit from our production and would operate at
a loss. In recent decades, there have been periods of both worldwide
overproduction and underproduction of hydrocarbons and periods of both increased
and relaxed energy conservation efforts. Such conditions have resulted in
periods of excess supply of, and reduced demand for, crude oil on a worldwide
basis and for natural gas on a domestic basis. These periods have been followed
by periods of short supply of, and increased demand for, crude oil and natural
gas. The excess or short supply of crude oil has placed pressures on prices and
has resulted in dramatic price fluctuations even during relatively short periods
of seasonal market demand.
Our use of hedging arrangements could result in financial losses or reduce
our income. We currently engage in hedging arrangements to reduce our exposure
to fluctuations in the prices of oil and natural gas. These hedging arrangements
expose us to risk of financial loss in some circumstances, including when
production is less than expected; the counter-party to the hedging contract
defaults on its contract obligations; or there is a change in the expected
differential between the underlying price in the hedging agreement and the
actual prices received. In addition, these hedging arrangements may limit the
benefit we would otherwise receive from increases in prices for oil and natural
gas.
Competition could ultimately lead to lower levels of profits and lower cash
flow. We face competition from other pipelines and terminals in the same markets
as our assets, as well as from other means of transporting and storing energy
products. For a description of the competitive factors facing our business,
please see Items 1 and 2 "Business and Properties" in this report for more
information.
We do not own approximately 97.5% of the land on which our pipelines are
constructed and we are subject to the possibility of increased costs to retain
necessary land use. We obtain the right to construct and operate the pipelines
on other people's land for a period of time. If we were to lose these rights or
be required to relocate our pipelines, our business could be affected
negatively.
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Southern Pacific Transportation Company has allowed us to construct and
operate a significant portion of our Pacific operations' pipeline system on
railroad rights-of-way. Southern Pacific Transportation Company and its
predecessors were given the right to construct their railroad tracks under
federal statutes enacted in 1871 and 1875. The 1871 statute was thought to be an
outright grant of ownership that would continue until the land ceased to be used
for railroad purposes. Two United States Circuit Courts, however, ruled in 1979
and 1980 that railroad rights-of-way granted under laws similar to the 1871
statute provide only the right to use the surface of the land for railroad
purposes without any right to the underground portion. If a court were to rule
that the 1871 statute does not permit the use of the underground portion for the
operation of a pipeline, we may be required to obtain permission from the
landowners in order to continue to maintain the pipelines. Approximately 10% of
our pipeline assets are located in the ground underneath railroad rights-of-way.
Whether we have the power of eminent domain for our pipelines varies from
state to state depending upon the type of pipeline--petroleum liquids, natural
gas or carbon dioxide--and the laws of the particular state. Our inability to
exercise the power of eminent domain could negatively affect our business if we
were to lose the right to use or occupy the property on which our pipelines are
located. For the year ended December 31, 2004, all of our right-of-way related
expenses totaled $16.7 million.
We could be treated as a corporation for United States income tax purposes.
Our treatment as a corporation would substantially reduce the cash distributions
on the common units that we distribute quarterly. The anticipated benefit of an
investment in our common units depends largely on the treatment of us as a
partnership for federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the Internal Revenue Service on this or any other
matter affecting us. Current law requires us to derive at least 90% of our
annual gross income from specific activities to continue to be treated as a
partnership for federal income tax purposes. We may not find it possible,
regardless of our efforts, to meet this income requirement or may inadvertently
fail to meet this income requirement. Current law may change so as to cause us
to be treated as a corporation for federal income tax purposes without regard to
our sources of income or otherwise subject us to entity-level taxation.
If we were to be treated as a corporation for federal income tax purposes,
we would pay federal income tax on our income at the corporate tax rate, which
is currently a maximum of 35% and would pay state income taxes at varying rates.
Under current law, distributions to unitholders would generally be taxed as a
corporate distribution. Because a tax would be imposed upon us as a corporation,
the cash available for distribution to a unitholder would be substantially
reduced. Treatment of us as a corporation would cause a substantial reduction in
the value of our units.
In addition, because of widespread state budget deficits, several states
are evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution
to our unitholders would be reduced.
Our debt instruments may limit our financial flexibility and increase our
financing costs. The instruments governing our debt contain restrictive
covenants that may prevent us from engaging in certain transactions that we deem
beneficial and that may be beneficial to us. The agreements governing our debt
generally require us to comply with various affirmative and negative covenants,
including the maintenance of certain financial ratios and restrictions on:
o incurring additional debt;
o entering into mergers, consolidations and sales of assets;
o granting liens; and
o entering into sale-leaseback transactions.
The instruments governing any future debt may contain similar or more
restrictive restrictions. Our ability to respond to changes in business and
economic conditions and to obtain additional financing, if needed, may be
restricted.
49
<PAGE>
If interest rates increase, our earnings could be adversely affected. As of
December 31, 2004, we had approximately $2.6 billion of debt, excluding market
value of interest rate swaps, subject to variable interest rates. This amount
included $2.2 billion of long-term fixed rate debt converted to floating rate
debt through the use of interest rate swaps. Should interest rates increase
significantly, our earnings could be adversely affected.
The distressed financial condition of some of our customers could have an
adverse impact on us in the event these customers are unable to pay us for the
services we provide. Some of our customers are experiencing severe financial
problems, and other customers may experience severe financial problems in the
future. The bankruptcy of one or more of them, or some other similar proceeding
or liquidity constraint might make it unlikely that we would be able to collect
all or a significant portion of amounts owed by the distressed entity or
entities. In addition, such events might force such customers to reduce or
curtail their future use of our products and services, which could have a
material adverse effect on our results of operations and financial condition.
In addition, some of our customers are experiencing, or may experience in
the future, severe financial problems that have had a significant impact on
their creditworthiness. We are working to implement, to the extent allowable
under applicable contracts, tariffs and regulations, prepayments and other
security requirements, such as letters of credit, to enhance our credit position
relating to amounts owed from these customers. We cannot provide assurance that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position, future results of operations
or future cash flows.
The interests of KMI may differ from our interest and the interests of our
unitholders. KMI indirectly owns all of the stock of our general partner and
elects all of its directors. Our general partner owns all of KMR's voting shares
and elects all of its directors. Furthermore, some of KMR's directors and
officers are also directors and officers of KMI and our general partner and have
fiduciary duties to manage the businesses of KMI in a manner that may not be in
the best interest of our unitholders. KMI has a number of interests that differ
from the interests of our unitholders. As a result, there is a risk that
important business decisions will not be made in the best interests of our
unitholders.
Our partnership agreement and the KMR limited liability company agreement
restrict or eliminate a number of the fiduciary duties that would otherwise be
owed by our general partner and/or its delegate to our unitholders.
Modifications of state law standards of fiduciary duties may significantly limit
the ability of our unitholders to successfully challenge the actions of our
general partner in the event of a breach of fiduciary duties. These state law
standards include the duties of care and loyalty. The duty of loyalty, in the
absence of a provision in the limited partnership agreement to the contrary,
would generally prohibit our general partner from taking any action or engaging
in any transaction as to which it has a conflict of interest. Our limited
partnership agreement contains provisions that prohibit limited partners from
advancing claims that otherwise might raise issues as to compliance with
fiduciary duties or applicable law. For example, that agreement provides that
the general partner may take into account the interests of parties other than us
in resolving conflicts of interest. It also provides that in the absence of bad
faith by the general partner, the resolution of a conflict by the general
partner will not be a breach of any duty. The provisions relating to the general
partner apply equally to KMR as its delegate. It is not necessary for a limited
partner to sign our limited partnership agreement in order for the limited
partnership agreement to be enforceable against that person.
Other
We do not have any employees. KMGP Services Company, Inc. and Kinder
Morgan, Inc. employ all persons necessary for the operation of our business.
Generally we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc. for
the services of their employees. As of December 31, 2004, KMGP Services Company,
Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 6,072
employees. Approximately 1,206 hourly personnel at certain terminals and
pipelines are represented by labor unions under collective bargaining agreements
that expire between 2005 and 2009. KMGP Services Company, Inc. and Kinder
Morgan, Inc. consider relations with their employees to be good. For more
information on our related party transactions, see Note 12 of the notes to our
consolidated financial statements included elsewhere in this report.
50
<PAGE>
Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of such property. In many instances, lands over
which rights-of-way have been obtained are subject to prior liens which have not
been subordinated to the right-of-way grants. In some cases, not all of the
apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor, or, the pipeline may be required to
move its facilities at its own expense. Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. Some such permits require annual
or other periodic payments. In a few minor cases, property for pipeline purposes
was purchased in fee.
We believe that we have generally satisfactory title to the properties we
own and use in our businesses, subject to liens for current taxes, liens
incident to minor encumbrances, and easements and restrictions which do not
materially detract from the value of such property or the interests in those
properties or the use of such properties in our businesses. We generally do not
own the land on which our pipelines are constructed. Instead, we obtain the
right to construct and operate the pipelines on other people's land for a period
of time. Amounts we have spent during 2004, 2003 and 2002 on research and
development activities were not material.
(d) Financial Information about Geographic Areas
The amount of our assets and operations that are located outside of the
continental United States of America are not material.
(e) Available Information
We make available free of charge on or through our Internet website, at
http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act
of 1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange Commission.
Item 3. Legal Proceedings.
See Note 16 of the notes to our consolidated financial statements included
elsewhere in this report.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of our unitholders during the
fourth quarter of 2004.
51
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters and Issuer Purchases of Equity Securities.
The following table sets forth, for the periods indicated, the high and low
sale prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, the amount of cash
distributions declared per common and Class B unit, and the fractional i-unit
distribution declared per i-unit.
Price Range
----------=-----
Cash i-unit
High Low Distributions Distributions
------ --------- ------------- -------------
2004
First Quarter $49.12 $43.50 $0.6900 0.017412
Second Quarter 45.39 37.65 0.7100 0.018039
Third Quarter 46.85 40.60 0.7300 0.017892
Fourth Quarter 47.70 42.75 0.7400 0.017651
2003
First Quarter $37.23 $33.51 $0.6400 0.018488
Second Quarter 40.34 35.00 0.6500 0.017138
Third Quarter 43.06 38.65 0.6600 0.016844
Fourth Quarter 49.95 42.63 0.6800 0.015885
All of the information is for distributions declared with respect to that
quarter. The declared distributions were paid within 45 days after the end of
the quarter. We currently expect that we will continue to pay comparable cash
and i-unit distributions in the future assuming no adverse change in our
operations, economic conditions and other factors. However, we can give no
assurance that future distributions will continue at such levels.
As of January 31, 2005, there were approximately 153,000 beneficial owners
of our common units, one holder of our Class B units and one holder of our
i-units.
For information on our equity compensation plans, see Item 12 "Security
Ownership of Certain Beneficial Owners and Management--Equity Compensation Plan
Information".
We did not repurchase any units during the fourth quarter of 2004.
52
<PAGE>
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated,
our summary historical financial and operating data. The table is derived from
our consolidated financial statements and notes thereto, and should be read in
conjunction with those audited financial statements. See also Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report for more information.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------
2004(4) 2003(5) 2002(6) 2001(7) 2000(8)
---------- ----------- ---------- ------------ ----------
(In thousands, except per unit data)
<S> <C> <C> <C> <C> <C>
Income and Cash Flow Data:
Revenues.......................... $ 7,932,861 $6,624,322 $4,237,057 $2,946,676 $ 816,442
Cost of product sold.............. 5,767,169 4,880,118 2,704,295 1,657,689 124,641
Operating expense................. 581,083 459,936 427,805 396,354 182,445
Fuel and power.................... 151,480 108,112 86,413 73,188 43,216
Depreciation, depletion and
amortization..................... 288,626 219,032 172,041 142,077 82,630
General and administrative........ 170,507 150,435 122,205 113,540 67,949
----------- ---------- ---------- ---------- ----------
Operating income.................. 973,996 806,689 724,298 563,828 315,561
Earnings from equity investments.. 83,190 92,199 89,258 84,834 71,603
Amortization of excess cost of
equity investments............... (5,575) (5,575) (5,575) (9,011) (8,195)
Interest expense.................. (196,172) (182,777) (178,279) (175,930) (97,102)
Interest income and other, net.... (4,135) (33) (6,042) (5,005) 10,415
Income tax provision.............. (19,726) (16,631) (15,283) (16,373) (13,934)
----------- ---------- ---------- ---------- -----------
Income before cumulative effect of a
change in accounting principle. 831,578 693,872 608,377 442,343 278,348
Cumulative effect of a change
in accounting principle.......... -- 3,465 -- -- --
----------- ---------- ---------- ---------- -----------
Net income........................ $ 831,578 $ 697,337 $ 608,377 $ 442,343 $ 278,348
General Partner's interest in
net income....................... 395,092 326,524 270,816 202,095 109,470
Limited Partners' interest in
net income....................... $ 436,486 $ 370,813 $ 337,561 $ 240,248 $ 168,878
Basic and Diluted Limited Partners'
Net Income per unit:
Income before cumulative effect
of a change in accounting
principle(1)..................... $ 2.22 $ 1.98 $ 1.96 $ 1.56 $ 1.34
Cumulative effect of a change
in accounting principle.......... -- 0.02 -- -- --
----------- ---------- ---------- ---------- -----------
Net income........................ $ 2.22 $ 2.00 $ 1.96 $ 1.56 $ 1.34
Per unit cash distribution
declared(2)...................... $ 2.87 $ 2.63 $ 2.435 $ 2.15 $ 1.712
Additions to property, plant
and equipment.................... $ 747,262 $ 576,979 $ 542,235 $ 295,088 $ 125,523
Balance Sheet Data (at end of period):
Net property, plant and equipment. $ 8,168,680 $7,091,558 $6,244,242 $5,082,612 $3,306,305
Total assets...................... $10,552,942 $9,139,182 $8,353,576 $6,732,666 $4,625,210
Long-term debt(3)................. $ 4,722,410 $4,316,678 $3,659,533 $2,237,015 $1,255,453
Partners' capital................. $ 3,896,520 $3,510,927 $3,415,929 $3,159,034 $2,117,067
</TABLE>
__________
(1) Represents income before cumulative effect of a change in accounting
principle per unit adjusted for the two-for-one split of units on August
31, 2001. Basic Limited Partners' income per unit before cumulative effect
of a change in accounting principle was computed by dividing the interest
of our unitholders in income before cumulative effect of a change in
accounting principle by the weighted average number of units outstanding
during the period. Diluted Limited Partners' net income per unit reflects
the potential dilution, by application of the treasury stock method, that
could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
(2) Represents the amount of cash distributions declared with respect to that
year. Amounts have been adjusted for the two-for-one split of common units
that occurred on August 31, 2001.
(3) Excludes market value of interest rate swaps.
(4) Includes results of operations for the seven refined petroleum products
terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an
additional 5% interest in the Cochin Pipeline System, Kinder Morgan River
Terminals LLC & Consolidated Subsidiaries, TransColorado Gas Transmission
Company, interests in nine refined petroleum products terminals acquired
from Charter Terminal Company and Charter-Triad Terminals, LLC, and the
Kinder Morgan Fairless
53
<PAGE>
Hills terminal since effective dates of acquisition. We acquired the seven
refined petroleum products terminals from ExxonMobil effective March 9,
2004. We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31,
2004. The additional interest in Cochin was acquired effective October 1,
2004. We acquired Kinder Morgan River Terminals LLC & Consolidated
Subsidiaries effective October 6, 2004. We acquired TransColorado effective
November 1, 2004, the interests in the nine Charter Terminal Company and
Charter-Triad Terminals, LLC refined petroleum products terminals effective
November 5, 2004, and the Kinder Morgan Fairless Hills terminal effective
December 1, 2004.
(5) Includes results of operations for the bulk terminal operations acquired
from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC
unit, the five refined petroleum products terminals acquired from Shell,
the additional 42.5% interest in the Yates field unit, the crude oil
gathering operations surrounding the Yates field unit, an additional 65%
interest in the Pecos Carbon Dioxide Company, the remaining approximate 32%
interest in MidTex Gas Storage Company, LLP, the seven refined petroleum
products terminals acquired from ConocoPhillips and two bulk terminal
facilities located in Tampa, Florida since dates of acquisition. We
acquired certain bulk terminal operations from M.J. Rudolph effective
January 1, 2003. The additional 12.75% interest in SACROC was acquired
effective June 1, 2003. The five refined petroleum products terminals were
acquired effective October 1, 2003. The additional 42.5% interest in the
Yates field unit, the Yates gathering system and the additional 65%
interest in Pecos Carbon Dioxide Company were acquired effective November
1, 2003. The additional 32% ownership interest in MidTex was acquired
November 1, 2003. The seven refined petroleum products terminals were
acquired December 11, 2003, and the two bulk terminal facilities located in
Tampa, Florida were acquired effective December 10 and 23, 2003.
(6) Includes results of operations for the additional 10% interest in the
Cochin Pipeline System, Kinder Morgan Materials Services LLC (formerly
Laser Materials Services LLC), the 66 2/3% interest in International Marine
Terminals, Tejas Gas, LLC, Milwaukee Bagging Operations, the remaining 33
1/3% interest in Trailblazer Pipeline Company, the Owensboro Gateway
Terminal and IC Terminal Holdings Company and Consolidated Subsidiaries
since dates of acquisitions. The additional interest in Cochin was acquired
effective December 31, 2001. Kinder Morgan Materials Services LLC was
acquired effective January 1, 2002. We acquired a 33 1/3% interest in
International Marine Terminals effective January 1, 2002 and an additional
33 1/3% interest effective February 1, 2002. Tejas Gas, LLC was acquired
effective January 31, 2002. The Milwaukee Bagging Operations were acquired
effective May 1, 2002. The remaining interest in Trailblazer was acquired
effective May 6, 2002. The Owensboro Gateway Terminal and IC Terminal
Holdings Company and Subsidiaries were acquired effective September 1,
2002.
(7) Includes results of operations for the remaining 50% interest in the Colton
Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas gas
gathering assets, 50% interest in Coyote Gas Treating, LLC, 25% interest in
Thunder Creek Gas Services, LLC, Central Florida Pipeline LLC, Kinder
Morgan Liquids Terminals LLC, Pinney Dock & Transport LLC, CALNEV Pipe Line
LLC, 34.8% interest in the Cochin Pipeline System, Vopak terminal LLCs,
Boswell terminal assets, Stolt-Nielsen terminal assets and additional
gasoline and gas plant interests since dates of acquisition. The remaining
interest in the Colton Processing Facility, Kinder Morgan Texas Pipeline,
Casper and Douglas gas gathering assets and our interests in Coyote and
Thunder Creek were acquired effective December 31, 2000. Central Florida
and Kinder Morgan Liquids Terminals LLC were acquired January 1, 2001.
Pinney Dock was acquired March 1, 2001. CALNEV was acquired March 30, 2001.
Our second investment in Cochin, representing a 2.3% interest, was made
effective June 20, 2001. Vopak terminal LLCs were acquired July 10, 2001.
Boswell terminals were acquired August 31, 2001. Stolt-Nielsen terminals
were acquired effective November 8 and 29, 2001, and our additional
interests in the Snyder Gasoline Plant and the Diamond M Gas Plant were
acquired effective November 14, 2001.
(8) Includes results of operations for Kinder Morgan Interstate Gas
Transmission, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar,
Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in
Kinder Morgan CO2 Company, L.P., Devon Energy carbon dioxide properties,
Kinder Morgan Transmix Company, LLC, a 32.5% interest in Cochin Pipeline
System and Delta Terminal Services LLC since dates of acquisition. Kinder
Morgan Interstate Gas Transmission, Trailblazer assets, and our 49%
interest in Red Cedar were acquired effective December 31, 1999. Milwaukee
Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired effective
January 1, 2000. The remaining 80% interest in Kinder Morgan CO2 Company,
L.P. was acquired April 1, 2000. The Devon Energy carbon dioxide properties
were acquired June 1, 2000. Kinder Morgan Transmix Company, LLC was
acquired effective October 25, 2000. Our 32.5% interest in Cochin was
acquired effective November 3, 2000, and Delta Terminal Services LLC was
acquired effective December 1, 2000.
54
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
The following discussion and analysis of our financial condition and results
of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis is based on our consolidated
financial statements, which are included elsewhere in this report and were
prepared in accordance with accounting principles generally accepted in the
United States of America. You should read the following discussion and analysis
in conjunction with our consolidated financial statements.
Additional sections in this report which should be helpful to your reading of
our discussion and analysis include the following:
o a description of our business strategy and management philosophy, found in
Items 1 and 2 "Business and Properties-Business Strategy";
o a description of developments during 2004, found in Items 1 and 2 "Business
and Properties-Recent Developments"; and
o a description of risk factors affecting us and our business, found in Items
1 and 2 "Business and Properties-Risk Factors."
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial statements
and related disclosures must be estimated, requiring us to make certain
assumptions with respect to values or conditions that cannot be known with
certainty at the time the financial statements are prepared. These estimates and
assumptions affect the amounts we report for assets and liabilities and our
disclosure of contingent assets and liabilities at the date of our financial
statements. We evaluate these estimates on an ongoing basis, utilizing
historical experience, consultation with experts and other methods we consider
reasonable in the particular circumstances. Nevertheless, actual results may
differ significantly from our estimates. Any effects on our business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others, which policies are discussed following.
Environmental Matters
With respect to our environmental exposure, we utilize both internal staff
and external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. Often, as the
remediation evaluation and effort progresses, additional information is
obtained, requiring revisions to estimated costs. These revisions are reflected
in our income in the period in which they are reasonably determinable.
We routinely conduct reviews of potential environmental issues and claims that
could impact our assets or operations. In December 2004, we recognized a $0.2
million increase in environmental expenses and an associated $0.1 million
increase in deferred income tax expense resulting from changes to previous
estimates. The adjustment included an $18.9 million increase in our estimated
environmental receivables and reimbursables and a $19.1 million increase in our
overall accrued environmental and related claim liabilities. We included the
additional $0.2 million environmental expense within "Other, net" in our
accompanying consolidated statement of income for 2004. The $0.3 million expense
item, including taxes, is the net impact of a $30.6 increase in expense in our
Products Pipelines business segment, a $7.6
55
<PAGE>
million decrease in expense in our Natural Gas Pipelines segment, a $4.1 million
decrease in expense in our CO2 segment, and an $18.6 million decrease in expense
in our Terminals business segment.
In December 2002, we recognized a $0.3 million reduction in environmental
expense and in our overall accrued environmental liability, and we included this
amount within "Other, net" in our accompanying consolidated statement of income
for 2002. The $0.3 million reduction in environmental expense resulted from a
$15.7 million increase in expense in our Products Pipelines business segment and
a $16.0 million decrease in expense in our Terminals business segment. For more
information on our environmental disclosures, see Note 16 to our consolidated
financial statements included elsewhere in this report.
Legal Matters
We are subject to litigation and regulatory proceedings as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected. We expense legal costs as incurred and
all recorded legal liabilities are revised as better information becomes
available.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding CALNEV Pipe Line LLC and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at
the Federal Energy Regulatory Commission involving shippers' complaints
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific operations' pipeline
systems. Generally, the interstate rates on our Pacific operations' pipeline
systems are "grandfathered" under the Energy Policy Act of 1992 unless
"substantially changed circumstances" are found to exist. To the extent
"substantially changed circumstances" are found to exist, our Pacific operations
may be subject to substantial exposure under these FERC complaints.
We estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million. As the
timing for implementation of rate reductions and the payment of reparations is
extended, total estimated reparations and the interest accruing on the
reparations increase. For each calendar quarter of delay in the implementation
of rate reductions sought, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the third quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
third quarter of 2006; however, the timing, and nature, of any rate reductions
and reparations that may be ordered will likely be affected by the FERC's income
tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues
remanded by the D.C. Circuit in the BP West Coast decision. If the phase two
initial decision were to be largely adopted by the FERC, the estimated
reparations and rate reductions would be larger than noted above; however, we
continue to estimate the combined annual impact of the rate reductions and the
capital costs associated with financing the payment of reparations sought by
shippers and accrued interest thereon to be approximately 15 cents of
distributable cash flow per unit. We believe, however, that the ultimate
resolution of these complaints will be for amounts substantially less than the
amounts sought. For more information on our Pacific operations' regulatory
proceedings, see Note 16 to our consolidated financial statements included
elsewhere in this report.
Intangible Assets
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141, "Business Combinations" and Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets." These accounting
pronouncements introduced the concept of indefinite life intangible assets and
required us to prospectively cease amortizing all of our intangible assets
having indefinite useful economic lives, including goodwill. Such assets are not
to be amortized until their lives are determined to be finite. These rules also
impact future period net income by an amount equal to the discontinued goodwill
amortization offset by goodwill impairment charges, if any, and adjusted for any
differences between the old and new rules for defining intangible assets on
future business combinations. Additionally, a recognized intangible asset with
an indefinite useful life
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<PAGE>
must be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We completed this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2005. As
of January 1, 2005, our goodwill was $732.8 million.
Estimated Net Recoverable Quantities of Oil and Gas
We use the successful efforts method of accounting for our oil and gas
producing activities. The successful efforts method inherently relies on the
estimation of proved reserves, both developed and undeveloped. The existence and
the estimated amount of proved reserves affect, among other things, whether
certain costs are capitalized or expensed, the amount and timing of costs
depleted or amortized into income and the presentation of supplemental
information on oil and gas producing activities. The expected future cash flows
to be generated by oil and gas producing properties used in testing for
impairment of such properties also rely in part on estimates of net recoverable
quantities of oil and gas.
Our estimation of net recoverable quantities of oil and gas is a highly
technical process performed primarily by in-house reservoir engineers and
geoscience professionals. Independent oil and gas consultants have reviewed the
estimates of proved reserves of crude oil, natural gas and natural gas liquids
that we have attributed to our net interest in oil and gas properties as of
December 31, 2004.
Proved reserves are the estimated quantities of oil and gas that geologic and
engineering data demonstrates with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively and
negatively, as additional information becomes available and as a contractual,
economic and political conditions change.
Results of Operations
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
2004 2003 2002
---------- ---------- ----------
(In thousands)
<S> <C> <C> <C>
Earnings before depreciation, depletion and
amortization expense and amortization of excess
cost of equity investments
Products Pipelines................................ $ 444,865 $ 441,600 $ 411,604
Natural Gas Pipelines............................. 418,261 373,350 325,454
CO2............................................... 357,636 203,599 132,196
Terminals......................................... 281,738 240,776 224,963
----------- ----------- -----------
Segment earnings before depreciation, depletion
and amortization of excess cost of equity
investments(a)................................ 1,502,500 1,259,325 1,094,217
Depreciation, depletion and amortization expense.. (288,626) (219,032) (172,041)
Amortization of excess cost of investments........ (5,575) (5,575) (5,575)
Interest and corporate administrative expenses(b). (376,721) (337,381) (308,224)
----------- ----------- -----------
Net income...................................... $ 831,578 $ 697,337 $ 608,377
=========== =========== ===========
</TABLE>
----------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses. 2004
amounts include environmental expense adjustments resulting in a
$30,611expense to our Products Pipelines business segment, a $7,602
reduction in expense to our Natural Gas Pipelines business segment, a
$4,126 reduction in expense to our CO2 business segment and an $18,571
reduction in expense to our Terminals business segment. 2002 amounts
include environmental expense adjustments resulting in a $15,700 expense to
our Products Pipelines business segment and a $16,000 reduction in expense
to our Terminals business segment.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense, loss from early
extinguishment of debt (2004 only) and cumulative effect adjustment from a
change in accounting principle (2003 only).
In 2004, we earned net income of $831.6 million ($2.22 per diluted unit) on
revenues of $7,932.9 million, compared to net income of $697.3 million ($2.00
per diluted unit) on revenues of $6,624.3 million in 2003, and net income of
$608.4 million ($1.96 per diluted unit) on revenues of $4,237.1 million in 2002.
We benefited from a growing demand for energy products, overall higher energy
prices and our management's continued commitment to its business strategy,
designed to increase financial performance through a combination of internal
asset expansions and external acquisitions.
In 2003, we benefited from a cumulative effect adjustment of $3.4 million
related to a change in accounting for asset retirement obligations pursuant to
our adoption of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" on January 1, 2003. Our 2003 income before the
cumulative effect adjustment totaled $693.9 million ($1.98 per diluted unit).
For more information on this cumulative effect adjustment from a change in
accounting principle, see Note 4 to our consolidated financial statements,
included elsewhere in this report.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we consider each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, to be an important measure of our success in maximizing
returns to our partners. In each of the years 2004 and 2003, all four of our
reportable business segments reported year-over-year increases in earnings
before depreciation, depletion and amortization, with the strongest growth
coming from our CO2 (carbon dioxide) and Natural Gas Pipelines business
segments.
The year-over-year increases in our segment earnings before depreciation,
depletion and amortization in 2004 and 2003 were attributable both to internal
growth and to contributions from acquired assets; more specifically:
57
<PAGE>
o higher earnings from our CO2 segment, where we benifited from higher oil and
gas prices, acquisitions of additional oil reserve interests and related
assets, and internal capital spending that both increased and expanded asset
infrastructure in order to accommodate growing customer demand within the
Permian Basin area of West Texas;
o higher earnings from our Natural Gas Pipelines segment, largely due to
improved margins on natural gas sales activities, higher natural gas
operational sales, and the further optimization of the large natural gas
sourcing and transportation operations we conduct within the State of Texas;
o higher earnings from our Products Pipelines segment, mainly due to higher
revenues from refined product terminal operations, higher deliveries of
refined petroleum products and natural gas liquids resulting from increased
military and industrial demand, and the acquisition of our Southeast
terminal operations, which consist of 23 refined petroleum products
terminals that were acquired since December 2003; and
o higher earnings from our Terminals segment, primarily due to higher revenues
earned by transporting and storing petroleum and petrochemical-related
liquids, transloading higher volumes of dry-bulk material products,
completed expansion projects at existing liquids and bulk terminal
facilities, and the terminal acquisitions we have made since the end of
2002.
We declared a record cash distribution of $0.74 per unit for the fourth
quarter of 2004 (an annualized rate of $2.96). This distribution was 9% higher
than the $0.68 per unit distribution we made for the fourth quarter of 2003, and
18% higher than the $0.625 per unit distribution we made for the fourth quarter
of 2002. We expect to declare cash distributions of at least $3.13 per unit for
2005; however, no assurance can be given that we will be able to achieve this
level of distribution. Our general partner and our common and Class B
unitholders receive quarterly distributions in cash, while KMR, the sole owner
of our i-units, receives quarterly distributions in additional i-units. The
value of the quarterly per-share distribution of i-units is based on the value
of the quarterly per-share cash distribution made to our common and Class B
unitholders.
Products Pipelines
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
2004 2003 2002
------------- ------------- ------------
(In thousands, except operating statistics)
<S> <C> <C> <C>
Revenues.................................................. $ 645,249 $ 585,376 $ 576,542
Operating expenses(a)..................................... (191,425) (169,526) (169,782)
Earnings from equity investments.......................... 29,050 30,948 28,998
Interest income and Other, net- income (expense)(b)....... (25,934) 6,471 (14,000)
Income taxes.............................................. $ (12,075) (11,669) (10,154)
------------ ------------- ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 444,865 441,600 411,604
investments.................................................
Depreciation, depletion and amortization expense.......... (71,263) (67,345) (64,388)
Amortization of excess cost of equity investments......... (3,281) (3,281) (3,281)
------------ ------------- ------------
Segment earnings........................................ $ 370,321 $ 370,974 $ 343,935
============ ============ ============
Gasoline (MMBbl).......................................... 459.1 451.0 465.2
Diesel fuel (MMBbl)....................................... 161.7 161.4 152.7
Jet fuel (MMBbl).......................................... 117.8 111.3 115.1
------------ ------------ ------------
Total refined product volumes (MMBbl)................... 738.6 723.7 733.0
Natural gas liquids (MMBbl)............................... 43.9 42.2 44.4
------------ ------------ ------------
Total delivery volumes (MMBbl)(c)....................... 782.5 765.9 777.4
============ ============ ============
</TABLE>
----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes expense of $30,611 and $15,700 in 2004 and 2002, respectively,
associated with environmental expense adjustments.
(c) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress
and Heartland pipeline volumes.
58
<PAGE>
Our Products Pipelines segment's primary businesses include transporting
refined petroleum products and natural gas liquids through pipelines and
operating high-quality liquid petroleum products terminals and transmix
processing facilities. The segment reported earnings before depreciation,
depletion and amortization of $444.9 million on revenues of $645.2 million in
2004. This compared to earnings before depreciation, depletion and amortization
of $441.6 million on revenues of $585.4 million in 2003 and earnings before
depreciation, depletion and amortization of $411.6 million on revenues of $576.5
million in 2002.
As noted in the table above, the segment's 2004 and 2002 earnings included
charges of $30.6 million and $15.7 million, respectively, from the adjustment
of our environmental liabilities referred to in "Critical Accounting Policies
and Estimates--Environmental Matters." Excluding these environmental charges,
segment earnings before depreciation, depletion and amortization totaled $475.5
million in 2004 and $427.3 million in 2002.
The $33.9 million (8%) increase in earnings before depreciation, depletion
and amortization in 2004 compared to 2003 (excluding the 2004 environmental
charge) was driven primarily by higher earnings from our Southeast terminals,
our Pacific operations, earnings from our proportionate ownership interest in
the Cochin pipeline system, and to a lesser extent by higher earnings from our
West Coast terminal operations, our Central Florida and Cypress pipelines, and
our transmix operations.
Our Southeast terminals, which include the operations of 23 refined products
terminals located in the southeastern United States that we acquired in December
2003, March 2004, and November 2004, reported earnings before depreciation,
depletion and amortization of $14.0 million in 2004. Our Pacific operations
reported a $9.5 million (4%) increase in earnings before depreciation, depletion
and amortization in 2004, compared to the prior year. The increase was primarily
due to incremental fees earned from ethanol-related services, higher refined
product delivery revenues, and incremental revenues related to the refined
products terminal operations we acquired from Shell Oil Products in October
2003.
Effective October 1, 2004, we acquired an additional undivided 5% interest
in the Cochin pipeline system for approximately $10.9 million and we now own
approximately 49.8% of Cochin, an approximate 1,900-mile pipeline that
transports natural gas liquids to the Midwestern United States and eastern
Canada petrochemical and fuel markets. Cochin's earnings before depreciation,
depletion and amortization increased $8.9 million (64%) in 2004 compared to
2003. The increase was primarily driven by higher revenues from pipeline
throughput deliveries as well as our additional ownership interest. Earnings
before depreciation, depletion and amortization from our West Coast terminals
increased $2.8 million (7%) in 2004 compared to 2003. The increase was largely
attributable to higher fees from ethanol blending services, primarily driven by
revenue increases across all service activities performed at our Carson,
California and our connected Los Angeles Harbor product terminals.
The increases in segment earnings before depreciation, depletion and
amortization in 2004 compared to 2003 were partly offset by lower earnings from
our CALNEV Pipeline and North System natural gas liquids pipeline. CALNEV and
the North System reported decreases of $2.4 million (5%) and $2.1 million (8%),
respectively, in earnings before depreciation, depletion and amortization in
2004 versus 2003. For CALNEV, the decrease was driven by higher 2004 fuel and
power expenses, higher operating expenses, and lower miscellaneous revenues. For
our North System, the decrease was primarily due to higher 2004 leased storage
expenses, due to higher fees, and lower transport revenues, related to a 6%
decrease in 2004 throughput delivery volumes. The decline in North System
delivery volumes was primarily due to a lack of propane supplies in February
through April of 2004, caused by shippers reducing line-fill and storage volume
to lower levels than last year. In April 2004, we filed a plan with the Federal
Energy Regulatory Commission to provide a line-fill service, which we expect
will mitigate the supply problems we experienced on our North System in the
first half of 2004. Pursuant to this plan, we purchased $23.0 million of
line-fill during 2004.
The $14.3 million (3%) increase in segment earnings before depreciation,
depletion and amortization in 2003 compared to 2002 (excluding the 2002
environmental charge) resulted from higher earnings from our Pacific operations,
North System, CALNEV Pipeline, transmix operations, Central Florida Pipeline,
our approximate 51% ownership interest in Plantation Pipe Line Company and our
West Coast terminal operations. Earnings in 2003 were positively impacted by
higher revenues, mainly from fees for ethanol blending services at our Pacific
operations and West Coast terminals, and from higher product delivery revenues
related to overall strong demand for diesel fuel. The overall increase was
partially offset by lower earnings before depreciation, depletion and
59
<PAGE>
amortization from both our proportionate interest in the Cochin pipeline system
and our Cypress Pipeline, mainly due to lower operating revenues. In addition,
due to the continued process of converting from methyl tertiary-butyl ether
(MTBE) to ethanol in the State of California, we realized a small reduction in
California gasoline volumes. Since the end of 2002, MTBE-blended gasoline is
being replaced by an ethanol blend, and ethanol is not shipped in our pipelines;
however, fees that we earn from ethanol-related services at our terminals
positively contribute to our earnings. As of December 31, 2003, we had ethanol
blending facilities in place at all of our California terminals necessary to
serve all of our customers.
The $59.8 million (10%) increase in segment revenues in 2004 compared to 2003
was driven by $23.2 million of incremental revenues attributable to the
acquisition of our Southeast terminals. In addition, revenues from our Pacific
operations increased $16.6 million (5%) and revenues from our proportionate
share of Cochin increased $13.1 million (53%). Our Pacific operations'
year-over-year increase was due to both the higher terminal revenues, discussed
above, and higher transport revenues, due largely to an almost 2% increase in
mainline delivery volumes. Cochin's increase in revenues was mainly due to a 30%
increase in delivery volumes and to higher average tariff rates. The increase in
delivery volumes in 2004 versus 2003 was partly related to lower product
inventory levels in western Canada in the first half of 2003, caused by a drop
in propane production. The drop in propane production was a reaction to lower
profit margins from the extraction and sale of natural gas liquids caused by a
rise in natural gas prices since the end of 2002. Revenues from our Central
Florida Pipeline increased $2.7 million (8%) in 2004 compared to 2003. The
increase was due to an almost 8% increase in product delivery volumes. Combined,
the segment benefited from a 2% increase in the volume of refined products
delivered during 2004 compared to 2003.
Combining all of the segment's operations, total throughput delivery of
refined petroleum products, consisting of gasoline, diesel fuel and jet fuel,
increased 2% in 2004 compared to 2003. Jet fuel delivery volumes, boosted by
strong military and solid commercial demand, were up nearly 6% in 2004 compared
to 2003, and gasoline delivery volumes increased 2%. Deliveries of diesel fuel
were essentially flat across both 2004 and 2003, but both gasoline and diesel
volumes were impacted in the fourth quarter of 2004 by the shut-down of a
refinery connected to the Plantation Pipeline following Hurricane Ivan.
The $8.9 million (2%) increase in segment revenues in 2003 compared to 2002
was driven by a $7.1 million (2%) increase in combined revenues from our Pacific
operations and West Coast terminals, largely due to increased terminal services.
Revenues from our North System increased $3.9 million (11%) in 2003 versus 2002.
Although throughput deliveries on our North System dropped by 4% in 2003, we
benefited from a 15% increase in average tariff rates as a result of an
increased cost of service tariff agreement filed with the Federal Energy
Regulatory Commission in May 2003. Revenues from our CALNEV Pipeline increased
$2.9 million (6%) in 2003 versus 2002, due to higher revenues from both refined
product deliveries and fees associated with ethanol blending operations. CALNEV
benefited from a 5% increase in the average tariff per barrel transported, due
mostly to an increase in transportation of longer-haul, higher margin barrels.
Revenues from our combined transmix operations increased $1.6 million (6%) in
2003 compared to 2002, primarily due to higher processing volumes at our
transmix facilities located in Richmond, Virginia and Indianola, Pennsylvania.
Revenues from our Central Florida Pipeline operations also increased by $1.6
million (5%) in 2003 versus 2002, due to higher storage revenues at our liquids
terminal located in Tampa, Florida and to higher refined product delivery
revenues associated with a 2% increase in delivery volumes.
The overall increase in segment revenues in 2003 compared to 2002 was offset
by a $7.5 million (23%) decrease in revenues from our investment in the Cochin
pipeline system and a $1.1 million (16%) decrease in revenues earned from our
Cypress Pipeline. In addition to the impact of lower propane production
described above, Cochin's 2003 earnings and revenues were negatively impacted by
a pipeline rupture and fire in July 2003 that led to the shut down of the system
for 29 days during the third quarter. The year-to-year drop in Cypress' revenues
was due to lower throughput volumes and to customers catching up on liquids
volumes earned but not delivered in prior periods.
For the segment as a whole, total throughput delivery of refined petroleum
products decreased 1% in 2003 compared to 2002. The decrease resulted from the
2003 transition from MTBE-blended gasoline to ethanol-blended gasoline, and the
fact that ethanol cannot be transported via pipeline but must instead be blended
at terminals. Our combined diesel and jet fuel deliveries, however, increased 2%
in 2003 versus 2002, mainly due to a 6% increase in diesel delivery volumes and
to improvement in jet fuel delivery volumes in the fourth quarter of 2003.
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<PAGE>
The segment's operating expenses increased $21.9 million (13%) in 2004
compared to 2003. The increase was mainly due to incremental expenses of $9.3
million from our Southeast terminals and to a $3.8 million (5%) increase in
expenses from our Pacific operations, largely the result of higher 2004 fuel and
power expenses associated with higher utility rates and higher delivery volumes.
The segment also reported $1.6 million year-over-year increases in expenses in
2004 from each of the Cochin Pipeline, North System, CALNEV Pipeline and
Plantation Pipeline. Cochin's increase was related to higher expenses associated
with the increased delivery volumes and our additional ownership interest. The
North System's increase was primarily due to higher natural gas liquids storage
expenses. CALNEV's increase was mostly due to higher fuel and power expenses due
to favorable credit adjustments to electricity access and surcharge reserves
taken in the first nine months of 2003. Plantation's increase was primarily
related to higher 2004 labor, testing and maintenance expenses. The segment's
operating expenses remained relatively flat in 2003, compared to 2002.
Earnings from our Products Pipelines' equity investments were $29.1 million in
2004, $30.9 million in 2003 and $29.0 million in 2002. Earnings from equity
investments consist primarily of earnings from our approximate 51% ownership
interest in Plantation Pipe Line Company and our 50% ownership interest in
Heartland Pipeline Company, both accounted for under the equity method of
accounting.
The $1.8 million (6%) decrease in equity earnings in 2004 compared to 2003
was mainly due to a $2.4 million (8%) decrease in equity earnings from
Plantation, mainly due to a $3.2 million expense recorded in the first quarter
of 2004 for our share of an environmental litigation settlement reached between
Plantation and various plaintiffs. In 2005, we expect to recover the cost of the
settlement under various insurance policies. The $1.9 million (7%) increase in
equity earnings in 2003 versus 2002 was primarily due to a $1.5 million (5%)
increase in equity earnings related to our ownership interest in Plantation. The
increase resulted primarily from higher litigation settlement costs recognized
during the fourth quarter of 2002, partially offset by lower earnings from
product deliveries in 2003.
Excluding the 2004 and 2002 environmental charges, interest and other income
items decreased $1.8 million in 2004 versus 2003, and increased $4.8 million in
2003 versus 2002. Both changes were largely due to higher gains realized from
sales of property, plant and equipment by our Pacific operations during 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $74.5 million, $70.6 million
and $67.7 million in each of the years ended December 31, 2004, 2003 and 2002,
respectively. The $3.9 million (6%) increase in 2004 versus 2003 was primarily
due to incremental depreciation charges from our Southeast terminals and to
higher depreciation expenses from our Pacific operations. The $2.9 million (4%)
increase in 2003 versus 2002 was driven by higher property and plant
depreciation expenses from our Pacific operations, CALNEV Pipeline and West
Coast terminals. Excluding the incremental depreciation expenses related to the
acquisition of our Southeast terminals, the year-over-year increases in
depreciation expenses in both 2004 and 2003 related to the capital spending we
have made since the end of 2002 in order to strengthen and enhance our business
operations on the West Coast.
For 2005, we currently expect that our Products Pipelines segment will report
earnings before depreciation, depletion and amortization expense of
approximately $535 million, a 13% increase over 2004 (excluding the 2004
environmental charge). The earnings increase is expected to be driven by
continued improvement in gasoline and jet fuel delivery volumes, planned capital
improvements and expansions (including our Pacific operations' North Line
expansion completed in December 2004), and a full year of operations from
products terminals acquired in March and November 2004.
61
<PAGE>
Natural Gas Pipelines
<TABLE>
<CAPTION>
Year Ended December 31,
2004 2003 2002
----------- ----------- -----------
(In thousands, except operating statistics)
<S> <C> <C> <C>
Revenues.................................................. $ 6,252,921 $ 5,316,853 $ 3,086,187
Operating expenses(a)..................................... (5,862,159) (4,967,531) (2,784,278)
Earnings from equity investments.......................... 19,960 24,012 23,887
Other, net - income(b).................................... 9,434 1,082 36
Income taxes.............................................. (1,895) (1,066) (378)
----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 418,261 373,350 325,454
Depreciation, depletion and amortization expense.......... (53,112) (53,785) (48,411)
Amortization of excess cost of equity investments......... (277) (277) (277)
----------- ----------- -----------
Segment earnings........................................ $ 364,872 $ 319,288 $ 276,766
=========== =========== ===========
Natural gas transport volumes (Trillion Btus)(c).......... 1,353.0 1,364.1 1,261.1
=========== =========== ===========
Natural gas sales volumes (Trillion Btus)(d).............. 992.4 906.0 882.8
=========== =========== ===========
</TABLE>
----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes income of $7,602 in 2004 associated with environmental expense
adjustments.
(c) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural
gas pipeline group, Trailblazer and TransColorado pipeline volumes.
TransColorado annual volumes are included for all three years (acquisition
date November 1, 2004).
(d) Represents Texas intrastate natural gas pipeline group. Kinder Morgan Tejas
sales volumes are included for all three years (acquisition date January 31,
2002).
Our Natural Gas Pipelines segment's primary businesses involve marketing,
transporting and storing natural gas through both intrastate and interstate
pipeline systems. In 2004, the segment reported earnings before depreciation,
depletion and amortization of $418.3 million on revenues of $6,252.9 million.
This compared to earnings before depreciation, depletion and amortization of
$373.4 million on revenues of $5,316.9 million in 2003 and earnings before
depreciation, depletion and amortization of $325.5 million on revenues of
$3,086.2 million in 2002.
As noted in the table above, the segment's 2004 earnings include a $7.6
million increase from the adjustment of our environmental liabilities referred
to in "Critical Accounting Policies and Estimates--Environmental Matters."
Excluding this environmental adjustment, segment earnings before depreciation,
depletion and amortization increased $37.3 million (10%) in 2004 compared to
2003. This increase, along with the $47.9 million (15%) increase in earnings
before depreciation, depletion and amortization in 2003 versus 2002, was
primarily attributable to higher earnings from our Texas intrastate natural gas
pipeline group, which includes the operations of the following four natural gas
pipeline systems: Kinder Morgan Tejas, Kinder Morgan Texas Pipeline, North Texas
Pipeline and Mier-Monterrey Mexico Pipeline.
The year-over-year increases in earnings before depreciation, depletion and
amortization from our Texas intrastate natural gas pipeline group were mainly
due to improved margins and higher volumes from natural gas sales activities,
strong returns from capital investments made since the end of 2002, and
incremental earnings from value added services, including storage, blending and
other services. Since our acquisition of Kinder Morgan Tejas on January 31,
2002, we have increased the interconnection capability between its system and
Kinder Morgan Texas Pipeline, improved system processes and controls and further
refined the management of risk associated with the sale and transmission of
natural gas. Kinder Morgan Tejas' operations include a 3,400-mile intrastate
natural gas pipeline system that has access to a number of natural gas supply
basins in the State of Texas; Kinder Morgan Texas Pipeline's operations include
approximately 2,500 miles of pipelines, supply and gathering lines, laterals and
related facilities principally located in the Texas Gulf Coast area. These two
systems comprise the major components of our Texas intrastate group and together
reported a $41.1 million (24%) increase in earnings before depreciation,
depletion and amortization in 2004 compared to 2003. In 2003, the two systems
combined reported a $30.7 million (22%) increase in earnings before
depreciation, depletion and amortization compared to 2002.
62
<PAGE>
Furthermore, we have continued to grow internally and have developed and
built new natural gas pipeline systems to transport gas from expanding
production areas and to serve new market areas. Contributions from the two
remaining Texas intrastate systems, our North Texas Pipeline, completed in
August 2002, and our Mier-Monterrey Pipeline, completed in March 2003, accounted
for $3.5 million (9%) of the segment's total increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003, and $14.9
million (31%) of the segment's total increase in earnings before depreciation,
depletion and amortization in 2003 compared to 2002. The increases were driven
by higher transportation revenues linked to growing demand for natural gas in
both Texas and the Monterrey, Mexico region.
Our Rocky Mountain interstate natural gas pipeline operations consist of the
following three natural gas pipeline systems: Kinder Morgan Interstate Gas
Transmission, Trailblazer Pipeline and TransColorado Pipeline. We acquired
TransColorado Gas Transmission Company from KMI effective November 1, 2004. The
TransColorado system includes a 300-mile interstate natural gas pipeline that
originates in the Piceance Basin of western Colorado and runs to the Blanco Hub
in northwest New Mexico. All three pipelines charge a transportation fee for gas
transmission service and have the authority to initiate natural gas sales
primarily for operational purposes, but none engage in significant gas purchases
for resale. Operational natural gas sales are primarily made possible by
collection of fuel in kind pursuant to each pipeline's natural gas
transportation tariff.
Together, our Rocky Mountain pipelines reported a $3.8 million (3%) decrease
in earnings before depreciation, depletion and amortization in 2004 compared to
2003. The decrease was due to lower earnings from our Trailblazer Pipeline,
mainly due to lower revenues as a result of timing on imbalance cashouts and
lower transportation revenues. The decreases in transportation revenues were due
to lower tariff rates that became effective January 1, 2004, pursuant to a rate
case settlement. In 2003, KMIGT and Trailblazer accounted for $4.6 million (10%)
of the segment's total increase in earnings before depreciation, depletion and
amortization compared to 2002. The increase in 2003 over 2002 was mainly due to
the benefits resulting from an expansion of our Trailblazer Pipeline system. In
May 2002, we completed a fully-subscribed, $48 million expansion project on the
Trailblazer system that expanded its transportation capacity by 324,000
dekatherms of natural gas per day. The expansion increased capacity on the
pipeline by approximately 60% and provided new firm long-term transportation
service. As a result, Trailblazer realized a 12% increase in natural gas
transportation volumes in 2003 compared to 2002.
In each of the years 2004 and 2003, the segment reported significant increases
in both revenues and operating expenses when compared to the year-earlier
period. Revenues earned by our Natural Gas Pipelines segment increased $936.0
million (18%) in 2004 versus 2003, and $2,230.7 million (72%) in 2003 versus
2002. Operating expenses, including natural gas purchase costs, increased $894.6
million (18%) in 2004 compared to 2003, and $2,183.3 million (78%) in 2003
compared to 2002.
The year-over-year increases in revenues and operating expenses were primarily
attributable to the internal growth and integration of our Kinder Morgan Tejas
and Kinder Morgan Texas Pipeline systems since the end of 2002. Both pipeline
systems buy and sell significant volumes of natural gas, which is also
transported on their pipelines, and our objective is to match purchases and
sales, thus locking-in the equivalent of a transportation fee. We manage
remaining price risk by the use of energy financial instruments. Combined, the
two systems reported increases in natural gas sales revenues of $912.2 million
(19%) in 2004 compared to 2003, and $2,117.6 million (78%) in 2003 compared to
2002. Both increases were due to higher average sale prices and higher sales
volumes; the increase in 2004 compared to 2003 resulted from an almost 9%
increase in average gas prices (from $5.32 per dekatherm in 2003 to $5.78 per
dekatherm in 2004) and an almost 10% increase in gas sales volumes. Revenues
from our recently acquired TransColorado Pipeline totaled $6.7 million in 2004.
Kinder Morgan Tejas and Kinder Morgan Texas Pipeline together reported
combined increases in costs of sales of $870.7 million (18%) in 2004 compared to
2003, and $2,123.3 million (80%) in 2003 compared to 2002. Both increases were
due to higher average costs of natural gas sold and higher volumes of gas
purchased for sale; the increase in 2004 compared to 2003 resulted from an 8%
increase in the average price of purchased gas (from $5.22 per dekatherm in 2003
to $5.66 per dekatherm in 2004) and a 9% increase in gas purchase volumes. Due
to the offsetting nature of gas sales and cost of gas sold, we believe that
earnings before depreciation, depletion and amortization or a similar measure of
margin, defined as revenues less cost of gas sold, is a better comparative
performance indicator than revenues because the mix of utility volumes between
sales and transportation service affects revenues but not margin.
63
<PAGE>
We account for the segment's investments in Red Cedar Gas Gathering Company,
Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity
method of accounting. In 2004, equity earnings from these three investees
decreased $4.1 million (17%) compared to 2003. The decrease was chiefly due to
lower earnings from our 49% investment in Red Cedar, mainly due to higher
operational sales of natural gas by Red Cedar in 2003. Earnings from equity
investments were relatively flat across 2003 and 2002; higher earnings in 2003
from our 25% investment in Thunder Creek were largely offset by lower earnings
from our investment in Red Cedar.
The segment's non-cash depreciation, depletion and amortization charges,
including amortization of excess cost of investments decreased a slight $0.7
million (1%) in 2004 compared to 2003, primarily due to lower year-to-year
depreciation expense on our Trailblazer Pipeline. The decrease was due to the
rate case settlement which became effective January 1, 2004. The $5.4 million
(11%) increase in depreciation, depletion and amortization charges in 2003 over
2002 was primarily due to incremental depreciation charges related to the
completed North Texas and Mier-Monterrey pipeline systems.
For 2005, we currently expect that our Natural Gas Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $439 million, a 7% increase over 2004 (excluding the 2004
environmental expense adjustment). The earnings increase is expected to be
driven by additional earnings realized from the sale of natural gas at higher
margins, increases in storage and transportation services, the benefits of
reaching new markets and customers by planned capital spending, and a full year
of operations from our TransColorado Pipeline.
CO2
<TABLE>
<CAPTION>
Year Ended December 31,
2004 2003 2002
--------- -------- --------
(In thousands, except operating statistics)
<S> <C> <C> <C>
Revenues....................................... $ 492,834 $248,535 $146,280
Operating expenses(a).......................... (173,382) (82,055) (50,524)
Earnings from equity investments............... 34,179 37,198 36,328
Other, net - income (expense)(b)............... 4,152 (40) 112
Income taxes................................... (147) (39) -
--------- -------- --------
Earnings before depreciation, depletion and
amortization expense and amortization of
excess cost of equity investments........... 357,636 203,599 132,196
Depreciation, depletion and amortization
expense(c).................................... (121,361) (60,827) (29,196)
Amortization of excess cost of equity
investments................................... (2,017) (2,017) (2,017)
--------- -------- --------
Segment earnings............................. $ 234,258 $140,755 $100,983
========= ======== ========
Carbon dioxide delivery volumes (Bcf)(d)......... 640.8 504.7 431.7
========= ======== ========
SACROC oil production (MBbl/d)(e)................ 28.3 20.2 13.0
========= ======== ========
Yates oil production (MBbl/d)(e)................. 19.5 18.9 18.3
========= ======== ========
Natural gas liquids sales volumes (MBbl/d)(f).... 7.7 3.7 2.1
========= ======== ========
Realized weighted average oil price per Bbl(g)(h) $ 25.72 $ 23.73 $ 22.45
========= ======== ========
Realized weighted average natural gas liquids
price per Bbl(h)(i).............................. $ 31.33 $ 21.77 $ 24.60
========= ======== ========
</TABLE>
----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes income of $4,126 in 2004 associated with environmental reserve
adjustments.
(c) Includes expenses associated with oil and gas production activities and gas
processing activities in the amount of $105,890 for 2004, $49,039 for 2003,
and $19,337 for 2002. Includes expenses associated with sales and
transportation services activities in the amount of $15,471 for 2004,
$11,788 for 2003, and $9,859 for 2002.
(d) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(e) Represents 100% of the production from the field.
(f) Net to Kinder Morgan.
(g) Includes all Kinder Morgan crude oil production properties.
(h) Hedge gains/losses for oil and natural gas liquids are included with
crude oil.
(i) Includes production attributable to leasehold ownership and production
attributable to our ownership in processing plants and third party
processing agreements.
64
<PAGE>
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, transportation and marketing of carbon dioxide, commonly called CO2,
and the production and marketing of crude oil and natural gas. In 2004, our CO2
segment reported earnings before depreciation, depletion and amortization of
$357.6 million on revenues of $492.8 million. This compared to earnings before
depreciation, depletion and amortization of $203.6 million on revenues of $248.5
million in 2003 and earnings before depreciation, depletion and amortization of
$132.2 million on revenues of $146.3 million in 2002.
As noted in the table above, the segment's 2004 earnings include a $4.1
million increase from the adjustment of our environmental liabilities referred
to in "Critical Accounting Policies and Estimates--Environmental Matters."
Excluding the increase from this environmental adjustment, segment earnings
before depreciation, depletion and amortization increased $149.9 million (74%)
in 2004 compared to 2003. This increase, along with the $71.4 million (54%)
increase in earnings before depreciation, depletion and amortization in 2003
over 2002, was driven by higher earnings from oil and gas producing activities
and gas processing activities, higher deliveries of carbon dioxide, and
strategic acquisitions of additional working interests in the SACROC and Yates
oil field units since the end of 2002.
Excluding earnings attributable to the 2004 environmental liability
adjustment, our CO2 segment's oil and gas producing activities and gas
processing activities reported earnings before depreciation, depletion and
amortization of $220.4 million in 2004, $103.6 million in 2003 and $51.5 million
in 2002. These increases of $116.8 million (113%) and $52.1 million (101%) from
2003 to 2004 and from 2002 to 2003, respectively, were primarily attributable to
increased oil production volumes, increases in the realized weighted average
price of oil per barrel, and acquisitions of additional ownership interests in
oil producing properties. These acquisitions included the following:
o effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
interest in the SACROC oil field unit for $23.3 million in cash and the
assumption of $1.9 million of liabilities. This transaction increased our
ownership interest in the SACROC unit to approximately 97%; and
o effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation for $230.2
million in cash and the assumption of $29.7 million of liabilities. The
assets acquired included Marathon's approximate 42.5% interest in the Yates
oil field unit, the crude oil gathering system surrounding the Yates field
unit and Marathon's 65% ownership interest in the Pecos Carbon Dioxide
Pipeline Company. This transaction increased our ownership interest in the
Yates oil field unit to nearly 50% and allowed us to become operator of the
field.
Excluding earnings attributable to the 2004 environmental liability
adjustment, our CO2 segment's carbon dioxide sales and carbon dioxide and crude
oil transportation activities reported earnings before depreciation, depletion
and amortization of $133.1 million in 2004, $100.0 million in 2003 and $80.7
million in 2002. The increase of $33.1 million (33%) in 2004 compared to 2003
was driven by higher revenues from carbon dioxide sales and deliveries, mainly
due to higher average carbon dioxide sale prices and higher transportation
volumes related to infrastructure expansions at the SACROC and Yates oil field
units. The increase of $19.3 million (24%) in earnings before depreciation,
depletion and amortization in 2003 compared to 2002 was chiefly due to higher
revenues from carbon dioxide pipeline delivery volumes, including the operations
of our Centerline carbon dioxide pipeline, which was completed and began
operations in May 2003.
Capacity and deliverability of carbon dioxide in and around the Permian Basin
has expanded since the end of 2002 in order to accommodate growing customer
demand. In 2004, capital expenditures for our CO2 business segment totaled
$302.9 million, 11% higher than the $272.2 million of capital expenditures made
during 2003, and 86% higher than the $163.2 million of expenditures in 2002. The
year-over-year increases largely represented incremental spending for new well
and injection compression facilities at the SACROC and, to a much lesser extent,
Yates oil field units in order to enhance oil recovery from carbon dioxide
injection.
In 2004, we also benefited from the acquisition of the Kinder Morgan Wink
Pipeline, a 450-mile crude oil pipeline located in West Texas. Effective August
31, 2004, we acquired all of the partnership interests in Kinder Morgan Wink
Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4 million in
liabilities. The
65
<PAGE>
acquisition of the pipeline and associated storage facilities allows us to
better manage crude oil deliveries from our oil field interests in West Texas.
The Wink Pipeline contributed $6.0 million in earnings before depreciation,
depletion and amortization during the last four months of 2004.
Revenues earned by our CO2 business segment increased $244.3 million (98%) in
2004 compared to 2003, and $102.2 million (70%) in 2003 compared to 2002. The
increases were mainly due to higher crude oil and gasoline plant product sales
revenues, driven by higher oil production volumes, higher average crude oil and
gasoline product prices, and the additional working interest in the Yates oil
field that we acquired in November 2003. Combined, the assets we acquired on
November 1, 2003 contributed incremental revenues of approximately $96.3 million
in 2004.
Daily oil production at the SACROC and Yates field units, both located in the
Permian Basin of West Texas, increased 40% and 3%, respectively, in 2004
compared to 2003, and 55% and 3%, respectively, in 2003 compared to 2002. We
also benefited from increases of 8% and 44%, respectively, in our realized
weighted average price of oil and natural gas liquids per barrel in 2004
compared to 2003, and a 6% increase in our realized weighted average price of
oil per barrel in 2003 compared to 2002. As a result of our carbon dioxide and
oil reserve ownership interests, we are exposed to commodity price risk
associated with physical crude oil and carbon dioxide sales that have pricing
tied to crude oil prices, but the risk is mitigated by our long-term hedging
strategy that is intended to generate more stable realized prices. For more
information on our hedging activities, see Note 14 to our consolidated financial
statements, included elsewhere in this report.
Additionally, in both 2004 and 2003, we realized higher revenues from carbon
dioxide transportation services. The year-over-year increases were mainly due to
higher transportation volumes, due to continued strong demand for carbon dioxide
throughout the Permian Basin. Combined deliveries of carbon dioxide on our
Central Basin Pipeline, our majority-owned Canyon Reef Carriers and Pecos
Pipelines, our Centerline Pipeline, and our 50% owned Cortez Pipeline, which is
accounted for under the equity method of accounting, increased 27% in 2004 and
17% in 2003. In 2004, we also realized higher revenues from carbon dioxide
sales, due to higher average prices; however, revenues from the sales of carbon
dioxide were lower in 2003 compared to 2002 due to a larger elimination of
intercompany profit, in 2003, related to an increase in the volumes of our
carbon dioxide utilized in our own operations. We do not recognize profits on
carbon dioxide sales to ourselves. Incremental revenues earned by our Kinder
Morgan Wink Pipeline totaled $7.8 million in 2004.
As discussed in Note 2 to our consolidated financial statements included
elsewhere in this report, the cost of carbon dioxide that is associated with
enhanced recovery is capitalized as part of our development costs when it is
injected. The carbon dioxide costs incurred and capitalized as development costs
for our CO2 segment were $70.6 million, $45.9 million and $31.0 million for the
years ended December 31, 2004, 2003 and 2002, respectively. We estimate that
such costs will be approximately $44.1 million, $55.8 million and $59.2 million
in 2005, 2006 and 2007, respectively. It is expected that, due to the nature of
this enhanced recovery process and the characteristics of the underlying
reservoir, the capitalized cost for carbon dioxide in 2007 will represent a peak
and is expected to decline thereafter. In addition, as of December 31, 2004, our
projected expenditures for developing our proved undeveloped reserves will be
approximately $183.4 million in 2005, $121.7 million in 2006, and $68.6 million
in 2007.
Both the $91.3 million (111%) increase in operating expenses in 2004 versus
2003, and the $31.5 million (62%) increase in operating expenses in 2003 versus
2002, were primarily related to higher operating and maintenance expenses,
higher fuel and power costs, and higher production taxes, all as a result of
higher oil production volumes, higher carbon dioxide delivery volumes, and
increases in oil reserve ownership interests and segment assets.
Earnings from equity investments decreased $3.0 million (8%) in 2004 compared
to 2003. The decrease resulted from the absence of equity earnings, in 2004,
from our previous 15% ownership interest in MKM Partners, L.P. Following our
June 1, 2003 acquisition of its 12.75% interest in the SACROC unit, MKM Partners
was dissolved effective June 30, 2003, and the lack of equity earnings in 2004
more than offset a $2.0 million (6%) increase in equity earnings from our 50%
investment in the Cortez Pipeline Company. The increase in equity earnings from
Cortez was mainly due to higher carbon dioxide delivery volumes in 2004 versus
2003. The $0.9 million (2%) increase in earnings from equity investments in 2003
compared to 2002 reflects the net of a $4.1 million (14%) increase in equity
earnings from our 50% investment in Cortez Pipeline Company, partially offset by
a $3.2 million (39%) decrease in equity earnings from our previous 15% interest
in MKM Partners, L.P. The increase in earnings
66
<PAGE>
from our equity interest in Cortez was mainly due to higher carbon dioxide
delivery volumes, lower average debt balances and slightly lower borrowing
rates.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, were up $60.5 million (96%)
in 2004 compared to 2003 and $31.6 million (101%) in 2003 compared to 2002. The
increases were primarily due to year-over-year increases in production volumes,
capital investments, and acquisitions of property interests. In addition, the
capital additions we have made since the end of 2002 have increased the
unit-of-production depletion rates.
For 2005, we currently expect that our CO2 segment will report earnings before
depreciation, depletion and amortization expense of approximately $474 million,
a 34% increase over 2004 (excluding the 2004 environmental expense adjustment).
The earnings increase is expected to be driven by the continuing development of
the SACROC and Yates oil field units.
Terminals
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
2004 2003 2002
--------- --------- ---------
(In thousands, except operating statistics)
<S> <C> <C> <C>
Revenues.................................................. $ 541,857 $ 473,558 $ 428,048
Operating expenses(a)..................................... (272,766) (229,054) (213,929)
Earnings from equity investments.......................... 1 41 45
Other, net - income(b).................................... 18,255 88 15,550
Income taxes(c)........................................... (5,609) (3,857) (4,751)
--------- --------- ---------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 281,738 240,776 224,963
Depreciation, depletion and amortization expense.......... (42,890) (37,075) (30,046)
Amortization of excess cost of equity investments......... - - -
--------- --------- ---------
Segment earnings........................................ $ 238,848 $ 203,701 $ 194,917
========= ========= =========
Bulk transload tonnage (MMtons)(d)........................ 67.7 61.2 58.7
========= ========= =========
Liquids leaseable capacity (MMBbl)........................ 36.8 36.2 35.3
========= ========= =========
Liquids utilization %..................................... 96.6% 96.0% 97.0%
========= ========= =========
</TABLE>
----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Includes income of $18,651 and $16,000 in 2004 and 2002, respectively,
associated with adjustments to environmental liabilities.
(c) Includes expense of $80 in 2004 associated with adjustments to environmental
liabilities.
(d) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
Our Terminals segment includes the operations of our coal, petroleum coke,
steel and other dry-bulk material terminals, as well as all the operations of
our petroleum and petrochemical-related liquids terminal facilities. The segment
reported earnings before depreciation, depletion and amortization of $281.7
million on revenues of $541.9 million in 2004. This compared to earnings before
depreciation, depletion and amortization of $240.8 million on revenues of $473.6
million in 2003 and earnings before depreciation, depletion and amortization of
$225.0 million on revenues of $428.0 million in 2002.
As noted in the table above, the segment's 2004 and 2002 earnings included
earnings of $18.6 million and $16.0 million, respectively, from the adjustment
of our environmental liabilities referred to in "Critical Accounting Policies
and Estimates--Environmental Matters." Excluding these environmental
adjustments, segment earnings before depreciation, depletion and amortization
increased $22.3 million (9%) in 2004 compared to 2003, and increased $31.8
million (15%) in 2003 compared to 2002.
The $22.3 million increase in earnings before depreciation, depletion and
amortization in 2004 over 2003 was driven by higher revenues from both our bulk
and liquids terminal businesses, due to (i) higher transfer volumes of bulk
products; (ii) higher demand for storage and distribution services offered for
petroleum and liquid chemical
67
<PAGE>
products; and (iii) additional storage and throughput capacity due to both
terminal acquisitions and the completion of capital projects since the end of
2003. Combined, our bulk terminal facilities reported an almost 11% increase in
total bulk tonnage volumes transloaded during 2004, as compared to 2003. In
turn, completed capital expansions and betterments at our liquids facilities
since the end of 2003, which included the construction of additional petroleum
products storage tanks, have increased our liquids storage capacity by
approximately 600,000 barrels (2%), and at the same time, we have increased our
liquids utilization capacity.
For terminal operations owned during both 2004 and 2003, growth in both
segment earnings before depreciation, depletion and amortization charges and
segment revenues were primarily attributable to record throughput at our Gulf
Coast liquids terminals, and to higher coal, bulk and synfuel volumes from
certain of our Mid-Atlantic terminals, which include our Chesapeake Bay,
Maryland bulk terminal and our Pier IX bulk terminal located in Newport News,
Virginia. Our two Gulf Coast liquids terminals, located on the Houston, Texas
Ship Channel, reported a combined $3.8 million increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003. The increase
was driven by a $7.1 million increase in revenues resulting from higher
throughput volumes, contract price escalations, additional service contracts and
new pipeline connections.
Our Chesapeake Bay facility reported a $2.7 million increase in earnings
before depreciation, depletion and amortization in 2004 compared to 2003. The
increase was driven by a $7.5 million increase in revenues, earned by providing
additional stevedoring services and storage and transportation for products such
as coal, petroleum coke, pig iron and steel slag. Our Pier IX terminal, which
transloads both coal and cement and operates a synfuel plant on site, reported a
$4.0 million increase in earnings before depreciation, depletion and
amortization in 2004 compared to 2003. The increase was driven by a $6.3 million
increase in revenues resulting from higher synfuel revenues and coal activity.
In February 2004, Pier IX began to operate a second synfuel plant on site.
Approximately half of the $31.8 million increase in earnings before
depreciation, depletion and amortization in 2003 over 2002 was attributable to
expansion projects at existing liquids terminals, and the remainder was
attributable to contributions from the bulk and liquid terminal businesses we
acquired since September 1, 2002. Terminal acquisitions completed since the
fourth quarter of 2003 helped increase both segment earnings before
depreciation, depletion and amortization and segment revenues in 2004 versus
2003. These acquisitions primarily consisted of the following:
o the Kinder Morgan Tampaplex marine terminal and inland bulk storage
warehouse facility, both located in Tampa, Florida and acquired in December
2003;
o the terminals owned and operated by Kinder Morgan River Terminals LLC and
its consolidated subsidiaries, acquired effective October 6, 2004; and
o the Kinder Morgan Fairless Hills bulk terminal facility, acquired effective
December 1, 2004.
Combined, these businesses, in 2004, contributed incremental earnings before
depreciation, depletion and amortization of $9.7 million and incremental
revenues of $26.7 million.
Excluding earnings attributable to the 2002 environmental adjustments, $15.1
million (47%) of the segment's $31.8 million increase in earnings before
depreciation, depletion and amortization, and $14.9 million (33%) of the total
$45.6 million (11%) increase in revenues in 2003 versus 2002 was attributable to
internal growth, largely resulting from the expansion projects undertaken to
increase leaseable liquids capacity at our liquids terminal facility located in
Carteret, New Jersey on the New York Harbor, and at our two Gulf Coast liquids
terminals. We completed the construction of five 100,000 barrel petroleum
products storage tanks at our Carteret facility since the end of the third
quarter of 2002. Combined, these expansion projects contributed to an almost 3%
increase in our overall liquids terminals' leaseable capacity in 2003 compared
to 2002, more than offsetting the slight 1% drop in our overall utilization
percentage in 2003. Over half of the decline in utilization during 2003 was
associated with tank maintenance.
In addition to the contributions to earnings and revenues that were
attributable to capital expansions, we benefited from additional liquids storage
contracts, escalations in annual contract provisions at many of our liquids
facilities, and higher returns from our 66 2/3% ownership interest in the
International Marine Terminals Partnership.
68
<PAGE>
IMT, which operates a bulk commodity transfer terminal facility located in Port
Sulphur, Louisiana, reported increases of $1.5 million in earnings before
depreciation, depletion and amortization, and $5.1 million in revenues in 2003
versus 2002. The increases were driven by an almost 10% increase in bulk tonnage
transfer volume, primarily coal and iron ore, and by higher dockage revenues.
The remaining $16.7 million (53%) of the segment's year-to-year increase in
earnings before depreciation, depletion and amortization and $30.7 million (67%)
of the year-to-year increase in revenues in 2003 versus 2002 was attributable to
strategic acquisitions of new terminal businesses acquired since September 1,
2002, including the following:
o the Owensboro Gateway Terminal, acquired effective September 1, 2002;
o the St. Gabriel Terminal, acquired effective September 1, 2002;
o the purchase of four floating cranes at our bulk terminal facility in Port
Sulphur, Louisiana in December 2002;
o the bulk terminal businesses acquired from M.J. Rudolph Corporation,
effective January 1, 2003; and
o the two bulk terminal businesses in Tampa, Florida, acquired in December
2003.
The segment's overall increases in both earnings before depreciation,
depletion and amortization and revenues in 2003 compared to 2002 included
decreases of $1.8 million (24%) and $3.0 million (23%), respectively, from our
Cora coal terminal facility located near Cora, Illinois. The decrease in coal
revenues and earnings was primarily related to an expected decrease in coal
tonnage handled under contract for the Tennessee Valley Authority. The TVA has
diverted some of its business to new competing coal terminals that have come
on-line since the end of 2002.
Both the $43.7 million (19%) increase in operating expenses in 2004 compared
to 2003 and the $15.1 million (7%) increase in operating expenses in 2003
compared to 2002, were due to the year-over-year increases in bulk tonnage
transfer volumes, liquids throughput and storage capacity, and the terminal
acquisitions described above. The increases were primarily reflected as higher
operating, maintenance, fuel and electricity expenses, including payroll,
trucking, equipment rental and docking expenses, all related to increased
dry-bulk and liquids product transfers and ship conveyance activities.
Income tax expenses totaled $5.5 million in 2004 (excluding the $0.1 million
tax expense on earnings attributable to adjustments to the environmental
liabilities recorded by taxable entities), $3.9 million in 2003 and $4.8 million
in 2002. The $1.6 million (41%) increase in income tax expense in 2004 compared
to 2003 was primarily due to incremental expense related to the taxable income
of certain subsidiaries of Kinder Morgan River Terminals LLC. The $0.9 million
(19%) decrease in income tax expense in 2003 compared to 2002 was primarily due
to favorable tax adjustments related to the taxable income and tax-paying
obligations of Kinder Morgan Bulk Terminals, Inc. and its consolidated
subsidiaries.
Non-cash depreciation, depletion and amortization charges were $42.9 million,
$37.1 million and $30.0 million in each of the years ended December 31, 2004,
2003 and 2002, respectively. Both the $5.8 million (16%) increase in 2004 versus
2003 and the $7.1 million (24%) increase in 2003 versus 2002 were primarily due
to property acquisitions and capital spending, and to adjustments made to the
estimated remaining useful lives of depreciable property since the end of 2002.
For 2005, we currently expect that our Terminals segment will report earnings
before depreciation, depletion and amortization expense of approximately $288
million, a 9% increase over 2004 (excluding the 2004 environmental expense
adjustment, net of taxes). The earnings increase is expected to be driven by
on-going capital expansion projects, by expected increases in bulk tonnage
transfer volumes, and by incremental earnings from the inclusion of a full year
of operations from Kinder Morgan River Terminals LLC and the Kinder Morgan
Fairless Hills terminal.
69
<PAGE>
Other
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------
2004 2003 2002
----------- ----------- -----------
(In thousands - income/(expense))
<S> <C> <C> <C>
General and administrative expenses............... $ (170,507) $ (150,435) $ (122,205)
Unallocable interest, net......................... (194,973) (181,357) (176,460)
Minority interest................................. (9,679) (9,054) (9,559)
Loss from early extinguishment of debt............ (1,562) - -
Cumulative effect adjustment from change in
accounting principle............................. - 3,465 -
----------- ----------- -----------
Interest and corporate administrative expenses.. $ (376,721) $ (337,381) $ (308,224)
=========== =========== ===========
</TABLE>
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
We also included both the $1.6 million loss from our early extinguishment of
debt in 2004 and the $3.4 million benefit from the cumulative effect adjustment
of a change in accounting for asset retirement obligations as of January 1, 2003
(discussed above), as items not attributable to any business segment. The loss
from the early extinguishment of debt represented the excess of the price we
paid to repurchase and retire the principal amount of $87.9 million of
tax-exempt industrial revenue bonds over the bonds' carrying value. We assumed
these industrial revenue bonds as part of our January 2001 acquisition of Kinder
Morgan Liquids Terminals LLC. Pursuant to certain provisions that gave us the
right to call and retire the bonds prior to maturity, we took advantage of the
opportunity to refinance at lower rates. For more information on our early
extinguishment of debt, see Note 9 to our consolidated financial statements,
included elsewhere in this report.
Our general and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, legal fees, insurance and office
supplies and rentals. Overall general and administrative expenses totaled $170.5
million in 2004, compared to $150.4 million in 2003 and $122.2 million in 2002.
The $20.1 million (13%) increase in general and administrative expenses in 2004
compared to 2003 was principally due to higher employee bonus and benefit
expenses, higher corporate and employee-related insurance expenses, and higher
corporate service expenses, including legal, internal audit and human resources.
The $28.2 million (23%) increase in general and administrative expenses in 2003
compared to 2002 was primarily due to higher legal expenses, higher employee
benefit and pension costs and higher overall corporate and employee-related
insurance expenses. We continue to aggressively manage our infrastructure
expense and to focus on our productivity and expense controls.
Interest expense, net of interest income, totaled $195.0 million in 2004,
$181.4 million in 2003 and $176.5 million in 2002. Although our average
borrowing rates were essentially flat across both 2003 and 2004, we incurred a
$13.6 million (7%) increase in net interest charges in 2004 as a result of
higher average borrowings. The increase in average borrowings was primarily due
to higher capital spending related to internal expansions and improvements, and
to incremental borrowings made in connection with acquisition expenditures. For
more information on our capital expansion and acquisition expenditures, see
"Liquidity and Capital Resources - Investing Activities". The $4.9 million (3%)
increase in net interest items in 2003 compared to 2002 reflects higher average
borrowings since the end of 2002, partially offset by decreases in average
borrowing rates.
Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, totaled $9.7 million in 2004, compared to
$9.1 million in 2003 and $9.6 million in 2002. The $0.6 million (7%) increase in
2004 versus 2003 resulted mainly from higher overall partnership income, partly
offset by our November 2003 acquisition of the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP that we did not already
own, thereby eliminating the associated minority interest. The $0.5 million (5%)
decrease in 2003 compared to 2002 resulted primarily from our May 2002
acquisition of the remaining 33 1/3% ownership interest in Trailblazer Pipeline
Company that we did not already own, thereby eliminating the associated minority
interest.
Liquidity and Capital Resources
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 60% equity and 40% debt. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
70
<PAGE>
<TABLE>
<CAPTION>
December 31,
----------------------------------
2004 2003 2002
---------- ---------- ----------
<S> <C> <C> <C>
Long-term debt, excluding market value of interest $4,722,410 $4,316,678 $3,659,533
rate swaps...........................................
Minority interest.................................... 45,646 40,064 42,033
Partners' capital, excluding accumulated other
comprehensive loss................................... 4,353,863 3,666,737 3,461,186
---------- ---------- ----------
Total capitalization............................... 9,121,919 8,023,479 7,162,752
Short-term debt, less cash and cash equivalents...... - (21,081) (41,088)
---------- ---------- ----------
Total invested capital............................. $9,121,919 $8,002,398 $7,121,664
========== ========== ==========
Capitalization:
Long-term debt, excluding market value of interest
rate swaps........................................ 51.8% 53.8% 51.1%
Minority interest.................................. 0.5% 0.5% 0.6%
Partners' capital, excluding accumulated other
comprehensive loss................................... 47.7% 45.7% 48.3%
---------- ---------- ----------
100.0% 100.0% 100.0%
========== ========== ==========
Invested Capital:
Total debt, less cash and cash equivalents and
excluding market value of interest
rate swaps.................................... 51.8% 53.7% 50.8%
Partners' capital and minority interest, excluding
accumulated other comprehensive loss ........ 48.2% 46.3% 49.2%
---------- ---------- ----------
100.0% 100.0% 100.0%
========== ========== ==========
</TABLE>
We employ a centralized cash management program that essentially concentrates
the cash assets of our operating partnerships and their subsidiaries in joint
accounts for the purpose of providing financial flexibility and lowering the
cost of borrowing. Our centralized cash management program provides that funds
in excess of the daily needs of our operating partnerships and their
subsidiaries are concentrated, consolidated, or otherwise made available for use
by other entities within our consolidated group. We place no restrictions on the
ability to move cash between entities, payment of inter-company balances or the
ability to upstream dividends to parent companies.
In addition, certain of our operating subsidiaries are subject to Federal
Energy Regulatory Commission enacted reporting requirements for oil and natural
gas pipeline companies that participate in cash management programs.
FERC-regulated entities subject to these rules must, among other things, place
their cash management agreements in writing, maintain current copies of the
documents authorizing and supporting their cash management agreements, and file
documentation establishing the cash management program with the FERC.
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facility, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:
o cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with retained
cash (resulting from including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional i-units rather than cash), additional borrowings, the issuance of
additional common units or the issuance of additional i-units to KMR;
o interest payments with cash flows from operating activities;
and
o debt principal payments with additional borrowings, as such debt principal
payments become due, or by the issuance of additional common units or the
issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMR's purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.
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Short-term Liquidity
Our principal sources of short-term liquidity are our revolving bank credit
facility, our $1.25 billion short-term commercial paper program (which is
supported by our revolving bank credit facility, with the amount available for
borrowing under our credit facility being reduced by our outstanding commercial
paper borrowings) and cash provided by operations.
In August 2004, we replaced our previous 364-day and three-year credit
facilities, which had a combined borrowing capacity of $1.05 billion, with a
five-year senior unsecured revolving credit facility that has a borrowing
capacity of $1.25 billion. Our five-year bank facility is due August 18, 2009,
and can be used for general corporate purposes and as a backup for our
commercial paper program. There were no borrowings under our credit facility as
of December 31, 2004. After inclusion of our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank facility was $733.0 million as of December 31, 2004.
For the year ended December 31, 2004, we continued to generate strong cash
flow from operations, and we provided for additional liquidity by maintaining a
sizable amount of excess borrowing capacity related to our commercial paper
program and long-term revolving credit facility. As of December 31, 2004, our
outstanding short-term debt was $621.2 million. We intended and had the ability
to refinance all of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amounts have been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate. For more information on our credit
facility, see Note 9 to our consolidated financial statements included elsewhere
in this report.
Long-term Financing Transactions
Debt Financing
From time to time we issue long-term debt securities. All of our long-term
debt securities issued to date, other than those issued under our revolving
credit facilities, generally have the same terms except for interest rates,
maturity dates and prepayment premiums. All of our outstanding debt securities
are unsecured obligations that rank equally with all of our other senior debt
obligations. A modest amount of secured debt has been incurred by some of our
subsidiaries. Our fixed rate notes provide that we may redeem the notes at any
time at a price equal to 100% of the principal amount of the notes plus accrued
interest to the redemption date plus a make-whole premium.
On November 12, 2004, we closed a public offering of $500 million in principal
amount of 5.125% senior notes due November 15, 2014 at a price to the public of
99.914%. In the offering, we received proceeds, net of underwriting discounts
and commissions, of approximately $496.3 million. We used the proceeds to reduce
the then outstanding balance on our commercial paper borrowings. As of December
31, 2004, our total liability balance due on the various series of our senior
notes was approximately $4,189.6 million. For more information on our senior
notes, see Note 9 to our consolidated financial statements included elsewhere in
this report.
Equity Financing
On February 9, 2004, we issued, in a public offering, an additional 5,300,000
of our common units at a price of $46.80 per unit, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $237.8 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.
On November 10, 2004, we issued, in a public offering, an additional 5,500,000
of our common units at a price of $46.00 per unit, less commissions and
underwriting expenses. On December 8, 2004, we issued an additional 575,000
units upon the exercise by the underwriters of an over-allotment option. After
commissions and underwriting expenses, we received net proceeds of $268.3
million for the issuance of these 6,075,000 common units. We used the proceeds
to reduce the borrowings under our commercial paper program.
On March 25, 2004, KMR issued an additional 360,664 of its
shares at a price of $41.59 per share, less closing fees and
commissions. The net proceeds from the offering were used to buy
additional i-units from us. After
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closing and commission expenses, we received net proceeds of $14.9 million for
the issuance of 360,664 i-units. We used the proceeds from the i-unit issuance
to reduce the borrowings under our commercial paper program.
On November 10, 2004, KMR issued an additional 1,300,000 of its shares at a
price of $41.29 per share, less closing fees and commissions. The net proceeds
from the offering were used to buy additional i-units from us. We received
proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the
proceeds from the i-unit issuance to reduce the borrowings under our commercial
paper program.
Capital Requirements for Recent Transactions
During 2004, our cash outlays for the acquisitions of assets and equity
investments totaled $479.9 million. With the exception of our acquisition of
TransColorado, which was partially acquired by the issuance of additional common
units to KMI, we utilized our commercial paper program to fund these
acquisitions and then reduced our short-term borrowings with the proceeds from
our February and November 2004 issuances of common units, our March and November
2004 issuances of i-units, and our November 2004 issuance of long-term senior
notes. We intend to refinance the remainder of our current short-term debt and
any additional short-term debt incurred during 2005 through a combination of
long-term debt, equity and the issuance of additional commercial paper to
replace maturing commercial paper borrowings.
In February 2005, a shelf registration statement became effective that will
allow us to issue up to a total of $2 billion in debt and/or equity securities.
We are committed to maintaining a cost effective capital structure and we intend
to finance new acquisitions using a mix of approximately 60% equity financing
and 40% debt financing. For more information on our capital requirements during
2004 in regard to our acquisition expenditures, see Note 3 to our consolidated
financial statements included elsewhere in this report.
Summary of Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial
statements. As of December 31, 2004, our obligations with respect to these
investments, as well as our obligations with respect to a letter of credit, are
summarized below (in millions):
<TABLE>
<CAPTION>
Our
Our Remaining Total Total Contingent
Investment Ownership Interest(s) Entity Entity Share of
Entity Type Interest Ownership Assets(4) Debt Entity Debt(5)
--------------------------------- ---------- --------- -------------- --------- ------ --------------
<S> <C> <C> <C> <C> <C> <C>
General 50% (1) $114 $202 $101 (2)
Cortez Pipeline Company........ Partner
Red Cedar Gas Gathering General 49% Southern Ute $187 $47 $47
Company.................... Partner Indian Tribe
Nassau County, N/A N/A Nassau County, N/A N/A $25
Florida Ocean Highway Florida Ocean
and Port Authority (3)..... Highway and
Port Authority
</TABLE>
---------
(1) The remaining general partner interests are owned by ExxonMobil Cortez
Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil
Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
M.E. Zuckerman Energy Investors Incorporated.
(2) We are severally liable for our percentage ownership share of the Cortez
Pipeline Company debt. Further, pursuant to a Throughput and Deficiency
Agreement, the partners of Cortez Pipeline Company are required to
contribute capital to Cortez in the event of a cash deficiency. The
agreement contractually supports the financings of Cortez Capital
Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by
obligating the partners of Cortez Pipeline to fund cash deficiencies at
Cortez Pipeline, including anticipated deficiencies and cash deficiencies
relating to the repayment of principal and interest on the debt of Cortez
Capital Corporation. The partners' respective parent or other companies
further severally guarantee the obligations of the Cortez Pipeline owners
under this agreement.
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(3) Arose from our Vopak terminal acquisition in July 2001. Nassau County,
Florida Ocean Highway and Port Authority is a political subdivision of the
State of Florida. During 1990, Ocean Highway and Port Authority issued its
Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5
million for the purpose of constructing certain port improvements located in
Fernandino Beach, Nassau County, Florida. A letter of credit was issued as
security for the Adjustable Demand Revenue Bonds and was guaranteed by the
parent company of Nassau Terminals LLC, the operator of the port facilities.
In July 2002, we acquired Nassau Terminals LLC and became guarantor under
the letter of credit agreement. In December 2002, we issued a $28 million
letter of credit under our credit facilities and the former letter of credit
guarantee was terminated. As of December 31, 2004, the value of this letter
of credit outstanding under our credit facility was $25 million. Principal
payments on the bonds are made on the first of December each year and
reductions are made to the letter of credit.
(4) Principally property, plant and equipment.
(5) Represents the portion of the entity's debt that we may be responsible for
if the entity cannot satisfy the obligation.
We account for our investments in the Red Cedar Gas Gathering Company and
Cortez Pipeline Company under the equity method of accounting. For the year
ended December 31, 2004, our share of earnings, based on our ownership
percentage, before income taxes and amortization of excess investment cost was
$34.2 million from Cortez Pipeline Company, and $14.7 million from Red Cedar Gas
Gathering Company. Additional information regarding the nature and business
purpose of these investments is included in Notes 7 and 13 to our consolidated
financial statements included elsewhere in this report.
Summary of Certain Contractual Obligations
<TABLE>
<CAPTION>
Amount of Commitment Expiration per Period
---------------------------------------------------------------
1 Year After 5
Total or Less 2-3 Years 4-5 Years Years
---------- -------- -------- -------- ----------
(In thousands)
<S> <C> <C> <C> <C> <C>
Contractual Obligations:
Commercial paper outstanding...... $ 416,900 $416,900 $ -- $ -- $ --
Other debt borrowings(a)
Principal payments............... 4,305,510 204,268 297,734 252,871 3,550,637
Interest payments................ 3,502,266 275,608 519,671 481,145 2,225,842
Lease obligations(b).............. 166,418 30,678 50,160 35,465 50,115
Postretirement welfare plans(c)... 1,800 300 600 600 300
Other obligations(d).............. 94,755 15,229 25,307 21,495 32,724
---------- -------- -------- -------- ----------
Total............................. $8,487,649 $942,983 $893,472 $791,576 $5,859,618
========== ======== ======== ======== ==========
Other commercial commitments:
Standby letters of credit(e)...... $ 162,586 $132,253 $ 30,333 $ -- $ --
========== ======== ======== ======== ==========
Capital expenditures(f)........... $ 13,788 $ 13,788 - - -
========== ======== ======== ======== ==========
</TABLE>
----------
(a) Debt obligations exclude adjustments for interest rate swap agreements.
(b) Represents commitments for capital leases, including interest, and operating
leases.
(c) Represents expected annual contributions of $0.3 million per year based on
calculations of independent enrolled actuary as of December 31, 2004.
(d) Consist of payments due under carbon dioxide take-or-pay contracts, carbon
dioxide removal contracts and natural gas liquids joint tariff agreements.
(e) The $162.6 million in letters of credit outstanding as of December 31 2004
consisted of the following: (i) a $50 million letter of credit supporting
our hedging of commodity price risks; (ii) our $30.3 million guarantee under
letters of credit supporting our International Marine Terminals Partnership
Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iii) a
$25.9 million letter of credit supporting Nassau County, Florida Ocean
Highway and Port Authority tax-exempt bonds; (iv) a $25.4 million letter of
credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey
Economic Development Revenue Bonds; (v) a $24.1 million letter of credit
supporting our Kinder Morgan Operating L.P. "B" tax-exempt bonds; (vi) a
$5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois
Development
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Revenue Bonds; and (vii) three letters of credit totaling $1.5 million,
supporting workers' compensation insurance polices and equipment rental
obligations.
(f) Represents commitments for the purchase of plant, property and equipment as
of December 31, 2004.
In our 2005 sustaining capital expenditure plan, we have budgeted $125.8
million, primarily for the purchase of plant and equipment. Sustaining capital
expenditures are defined as capital expenditures which do not increase the
capacity of an asset. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary.
Operating Activities
Net cash provided by operating activities was $1,155.1 million in 2004,
versus $768.5 million in 2003. The $386.6 million (50%) period-to-period
increase in 2004 compared to 2003 includes the following cash flow increases:
o a $236.2 million increase in cash from overall higher partnership income in
2004, net of non-cash items including depreciation, depletion and
amortization charges and undistributed earnings from equity investments;
o a $141.7 million increase in cash inflows relative to net changes in working
capital items; and
o a $44.9 million increase related to transportation rate reparation and
refund payments made in 2003.
The higher partnership income reflects the increased level of segment
earnings before depreciation, depletion and amortization reported in 2004 and
discussed in "Results of Operations." The favorable inflows from working capital
in 2004 were mainly related to timing differences in the payments made on our
trade and related party account payables. In addition to timing differences, we
made higher payments to settle related party payables at the beginning of 2003,
primarily for reimbursements to KMI for costs related to the construction of our
Mier-Monterrey natural gas pipeline and for general and administrative services.
The reparation and refund payments made in 2003 were mandated under an order
from the Federal Energy Regulatory Commission pursuant to a consolidated
proceeding in FERC Docket OR92-8-000 concerning rates charged by our Pacific
operations on certain interstate portions of their products pipelines.
Offsetting the overall increase in cash provided by operating activities was a
$17.8 million (21%) decrease in distributions received from equity investments
and an $18.4 million decrease related to higher payments made in 2004 on
non-current accounts, most notably, higher capitalizable project costs and
higher cash settlements on long-term reserves and other deferred credits. The
decrease in distributions from our equity investments was primarily due to lower
distributions from our previous investment in MKM Partners, L.P. and our current
investment in the Red Cedar Gas Gathering Company. MKM Partners, L.P. was
dissolved on June 30, 2003, thereby eliminating our 15% equity ownership
interest, and the decrease in distributions from our 49% equity ownership
interest in Red Cedar related to its lower earnings in 2004 versus 2003.
Investing Activities
Net cash used in investing activities was $1,250.5 million for the year ended
December 31, 2004, compared to $943.1 million for the prior year. The $307.4
million (33%) increase in funds utilized in investing activities was mainly
attributable to higher payments made for capital expenditures, strategic
acquisitions, and incremental purchases of natural gas liquids related to the
initiation of our North System's line-fill program. Partially offsetting the
overall increase in cash used in investing activities was a $7.0 million (50%)
decrease in contributions to equity investments, mainly due to lower
contributions made to Plantation Pipe Line Company.
Including expansion and maintenance projects, our capital expenditures were
$747.3 million in 2004 versus $577.0 million in 2003. The $170.3 million (30%)
increase was mainly driven by higher capital investment in our Products
Pipelines and CO2 business segments, as we continued to expand and grow our
existing asset infrastructure
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by adding both throughput capacity to our products pipelines and production and
delivery capacity to our oil field and carbon dioxide flooding operations. Our
sustaining capital expenditures were $119.2 million for 2004, compared to $92.8
million for 2003.
Additionally, we continue to make significant investments in strategic
acquisitions to fuel future growth and increase unitholder value. During 2004,
our acquisition outlays for assets and investments totaled $479.9 million, a
$120.0 million (33%) increase over the $359.9 million spent for acquisitions in
2003. Both our 2004 and 2003 acquistion expenditures are discussed more fully in
Note 3 to our consolidated financial statements included elsewhere in this
report.
We also spent $23.0 million in 2004 pursuant to the implementation of our
North System's natural gas liquids line-fill program, as discussed in "Results
of Operations." The line-fill program calls for us to purchase natural gas
liquids to be used as pipeline line-fill and pass the carrying costs on to our
shippers through a cost of service filing with the FERC. As of December 31,
2004, we had purchased approximately 650,000 barrels of propane, normal butane
and natural gasoline, which we believe will help mitigate the operational
constraints that resulted from a lack of product supplies caused by shippers
reducing their inventory levels at the close of the winter season.
Financing Activities
Net cash provided by financing activities was $72.1 million in 2004, compared
to $156.8 million in 2003. The $84.7 million (54%) period-to-period decrease in
cash provided by financing activities resulted primarily from lower cash inflows
from overall debt financing activities and from higher partnership
distributions. These overall decreases in cash provided by financing activities
were partially offset by an increase in cash inflows from overall partnership
equity issuances and an increase in temporary cash book overdrafts.
During each of the years 2004 and 2003, we used our commercial paper
borrowings to fund our asset acquisitions, capital expansion projects and other
partnership activities, and we subsequently raised funds to refinance a portion
of those borrowings by completing public offerings of senior notes and by
issuing additional common units and i-units. We used the proceeds from these
debt and equity issuances to reduce our borrowings under our commercial paper
program.
In 2004, we received $257.0 million from overall debt financing activities,
which included both issuances and payments of debt, loans to related parties and
debt issuance costs. In 2003, our debt financing activities provided us with
$655.1 million in cash. The $398.1 million (61%) period-to-period net decrease
was primarily due to the following:
o a $215.4 million decrease in net incremental commercial paper borrowings in
2004 versus 2003;
o an $87.9 million decrease related to payments, in 2004, to redeem and retire
the principal amount of five series of tax-exempt bonds related to certain
liquids terminal facilities. Pursuant to certain provisions that gave us the
right to call and retire the bonds prior to maturity, we took advantage of
the opportunity to refinance at lower rates;
o a $96.3 million decrease related to a long-term loan we made to Plantation
Pipe Line Company in 2004, which corresponded to our 51.17% ownership
interest and allowed Plantation to pay all of its outstanding credit
facility and commercial paper borrowings. In exchange, we received a seven
year note receivable bearing interest at the rate of 4.72% per annum;
o a $28.4 million decrease related to payments made to retire a significant
portion of the $33.7 million of outstanding debt assumed as part of our
October 2004 acquisition of Kinder Morgan River Terminals, LLC;
o a $9.5 million decrease related to payments made to retire all of the
outstanding debt assumed as part of our August 2004 acquisition of Kinder
Morgan Wink Pipeline, L.P.; and
o a $37.1 million increase related to payments made in December 2003 to retire
the outstanding balance under SFPP, L.P.'s Series F notes.
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In addition, in each of November 2004 and 2003, we closed public offerings of
$500 million in principal amount of senior notes. The offerings resulted in cash
inflows, net of discounts and issuing costs, of $496.3 million and $493.6
million, respectively.
Cash distributions to all partners, consisting of our common and Class B
unitholders (including KMI), our general partner, and minority interests,
increased to $791.0 million in 2004 compared to $679.3 million in 2003. The
$111.7 million (16%) increase in distributions was due to increases in the per
unit cash distributions paid, the number of outstanding units and the resulting
increase in our general partner incentive distributions.
The $398.5 million period-to-period increase in cash inflows from additional
partnership equity issuances was related to the excess of cash received from our
2004 issuances of both common and i-units over cash received from our June 2003
issuance of common units. In 2004, we received proceeds of $574.1 million from
additional partnership equity issuances, primarily consisting of the following
(amounts are net of all commissions and underwriting expenses):
o $237.8 million received from our issuance of 5,300,000 common units in a
February 2004 public offering;
o $14.9 million received from our issuance of 360,664 i-units in March 2004 to
KMR;
o $268.3 million received from our issuance of 6,075,000 common
units in a November 2004 public offering; and
o $52.6 million received from our issuance of 1,300,000 i-units in November
2004 to KMR.
By comparison, in 2003, we received net proceeds of $175.6 million from
additional partnership equity issuances, mainly the result of $173.3 million
received from the issuance of 4,600,000 of our common units in a June 2003
public offering. In both 2003 and 2004, we used the proceeds from each of these
issuances to reduce the borrowings under our commercial paper program.
The $29.9 million period-to-period increase in cash inflows from cash book
overdrafts resulted from temporary increases in outstanding checks due to timing
differences in the payments of year-end accruals and outstanding vendor invoices
in 2004 versus 2003.
We paid distributions of $2.81 per unit in 2004 compared to $2.575 per unit in
2003. The 9% increase in distributions paid per unit principally resulted from
favorable operating results in 2004. We also distributed 3,500,512 and 3,342,417
i-units in quarterly distributions during 2004 and 2003, respectively, to KMR,
our sole i-unitholder. The amount of i-units distributed in each quarter was
based upon the amount of cash we distributed to the owners of our common and
Class B units during that quarter of 2004 and 2003. For each outstanding i-unit
that KMR held, a fraction of an i-unit was issued. The fraction was determined
by dividing the cash amount distributed per common unit by the average of KMR's
shares' closing market prices for the ten consecutive trading days preceding the
date on which the shares began to trade ex-dividend under the rules of the New
York Stock Exchange.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of "Available
Cash," as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available Cash consists generally of all of our cash
receipts, including cash received by our operating partnerships and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with
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which they can be associated. When KMR determines our quarterly distributions,
it considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level. For 2004,
2003 and 2002, we distributed 87.0%, 100.4% and 97.6%, of the total of cash
receipts less cash disbursements, respectively (calculations assume that KMR
unitholders received cash). The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.
Our general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, the cash equivalent of
distributions of i-units is treated as if it had actually been distributed for
purposes of determining the distributions to our general partner.
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners of
all classes of units have received a total of $0.17875 per unit in cash or
equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all classes
of units pro rata and 25% to our general partner until the owners of all
classes of units have received a total of $0.23375 per unit in cash or
equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. Our general partner's incentive distribution that
we declared for 2004 was $390.7 million, while the incentive distribution paid
to our general partner during 2004 was $370.5 million. The difference between
declared and paid distributions is due to the fact that our distributions for
the fourth quarter of each year are declared and paid in the first quarter of
the following year.
On February 14, 2005, we paid a quarterly distribution of $0.74 per unit for
the fourth quarter of 2004. This distribution was 9% greater than the $0.68
distribution per unit we paid for the fourth quarter of 2003 and 7% greater than
the $0.69 distribution per unit we paid for the first quarter of 2004. We paid
this distribution in cash to our common unitholders and to our Class B
unitholders. KMR, our sole i-unitholder, received additional i-units based on
the $0.74 cash distribution per common unit. We believe that future operating
results will continue to support similar levels of quarterly cash and i-unit
distributions; however, no assurance can be given that future distributions will
continue at such levels.
Litigation and Environmental
As of December 31, 2004, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $40.9 million. The reserve is primarily established
to address and clean up soil and ground water impacts from former releases to
the environment at facilities we have acquired. Reserves for each project are
generally established by reviewing existing documents, conducting interviews and
performing site inspections to determine the overall size and impact to the
environment. Reviews are made on a quarterly basis to determine the status of
the cleanup and the costs associated with the effort and to identify if the
reserve allocation is appropriately valued. In assessing environmental risks in
conjunction with proposed acquisitions, we review records relating to
environmental issues, conduct site inspections, interview
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employees, and, if appropriate, collect soil and groundwater samples.
Please refer to Note 16 to our consolidated financial statements included
elsewhere in this report for additional information on our pending environmental
and litigation matters, respectively. We believe we have established adequate
environmental and legal reserves such that the resolution of pending
environmental matters and litigation will not have a material adverse impact on
our business, cash flows, financial position or results of operations. However,
changing circumstances could cause these matters to have a material adverse
impact.
Regulation
The Pipeline Safety Improvement Act of 2002 requires pipeline companies to
perform integrity tests on natural gas transmission pipelines that exist in high
population density areas that are designated as High Consequence Areas. Pipeline
companies are required to perform the integrity tests within ten years of
December 17, 2002, the date of enactment, and must perform subsequent integrity
tests on a seven year cycle. At least 50% of the highest risk segments must be
tested within five years of the enactment date. The risk ratings are based on
numerous factors, including the population density in the geographic regions
served by a particular pipeline, as well as the age and condition of the
pipeline and its protective coating. Testing will consist of hydrostatic
testing, internal electronic testing, or direct assessment of the piping. A
similar integrity management rule for refined petroleum products pipelines
became effective May 29, 2001. All baseline assessments for products pipelines
must be completed by March 31, 2008, and at least half of the line pipe
affecting High Consequence Areas was required to be assessed by September 30,
2004. We have included all incremental expenditures estimated to occur during
2005 associated with the Pipeline Safety Improvement Act of 2002 and the
integrity management of our products pipelines in our 2005 budget and capital
expenditure plan.
Please refer to Note 16 to our consolidated financial statements included
elsewhere in this report for additional information regarding regulatory
matters.
Recent Accounting Pronouncements
Please refer to Note 17 to our consolidated financial statements included
elsewhere in this report for information concerning recent accounting
pronouncements.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," or the negative of those terms or other variations
of them or comparable terminology. In particular, statements, express or
implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may differ
materially from those expressed in these forward-looking statements. Many of the
factors that will determine these results are beyond our ability to control or
predict. Specific factors which could cause actual results to differ from those
in the forward-looking statements include:
o price trends and overall demand for natural gas liquids, refined petroleum
products, oil, carbon dioxide, natural gas, coal and other bulk materials
and chemicals in the United States;
o economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to make
expansions to our facilities;
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o difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to or from our terminals or pipelines;
o our ability to successfully identify and close acquisitions and make cost-
saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use our
services or provide services or products to us;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may adversely
affect our business or our ability to compete;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of
our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared to our competitors that have
less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other causes;
o our ability to obtain insurance coverage without a significant level of
self-retention of risk;
o acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o capital markets conditions;
o the political and economic stability of the oil producing nations of the
world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
o the timing and extent of changes in commodity prices for oil,
natural gas, electricity and certain agricultural products;
o the extent of our success in discovering, developing and producing oil and
gas reserves, including the risks inherent in exploration and development
drilling, well completion and other development activities;
o engineering and mechanical or technological difficulties with operational
equipment, in well completions and workovers, and in drilling new wells;
o the uncertainty inherent in estimating future oil and natural
gas production or reserves;
o the timing and success of business development efforts; and
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o unfavorable results of litigation and the fruition of contingencies
referred to in Note 16 to our consolidated financial statements included
elsewhere in this report.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties--Risk Factors" for a more detailed
description of these and other factors that may affect the forward-looking
statements. When considering forward-looking statements, one should keep in mind
the risk factors described in "Risk Factors" above. The risk factors could cause
our actual results to differ materially from those contained in any
forward-looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been
determined to be "other than trading." Our exposure to market risk as discussed
below includes forward-looking statements and represents an estimate of possible
changes in fair value or future earnings that would occur assuming hypothetical
future movements in interest rates or commodity prices. Our views on market risk
are not necessarily indicative of actual results that may occur and do not
represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated, based on actual fluctuations
in interest rates or commodity prices and the timing of transactions.
Energy Financial Instruments
We are exposed to commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business. We take steps to limit
our exposure to these risks in order to maintain a more stable and predictable
earnings stream. Accordingly, we use energy financial instruments to reduce our
risks associated with changes in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. To minimize the risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide, we use certain financial instruments for hedging purposes. These
instruments include energy products traded on the New York Mercantile Exchange
and over-the-counter markets, including, but not limited to, futures and options
contracts, fixed-price swaps and basis swaps.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we purchase energy financial
instruments are as follows:
Credit Rating
-------------
Morgan Stanley......................... A+
J. Aron & Company / Goldman Sachs...... A+
BNP Paribas............................ AA
We account for our risk management derivative instruments under Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (after amendment by SFAS No. 137 and SFAS No. 138). As
discussed above, our principal use of derivative financial instruments is to
mitigate the market price risk associated with anticipated transactions for the
purchase and sale of natural gas, natural gas liquids, crude oil and carbon
dioxide. SFAS No. 133 allows these transactions to be treated as hedges for
accounting purposes, although the changes in the market value of these
instruments will affect comprehensive income in the period in which they occur
and any ineffectiveness in the risk mitigation performance of the hedge will
affect net income currently. The change in the market value of these instruments
representing effective hedge operation will continue to affect net income in the
period in which the associated physical transactions are consummated. Our
application of SFAS No. 133 has resulted in deferred net loss amounts of $457.3
million and $155.8 million being reported as "Accumulated other comprehensive
loss" in our accompanying balance sheets as of December 31, 2004 and December
31, 2003, respectively.
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We measure the risk of price changes in the natural gas, natural gas liquids,
crude oil and carbon dioxide markets utilizing a value-at-risk model.
Value-at-risk is a statistical measure of how much the mark-to-market value of a
portfolio could change during a period of time, within a certain level of
statistical confidence. We utilize a closed form model to evaluate risk on a
daily basis. The value-at-risk computations utilize a confidence level of 97.7%
for the resultant price movement and a holding period of one day chosen for the
calculation. The confidence level used means that there is a 97.7% probability
that the mark-to-market losses for a single day will not exceed the
value-at-risk number presented. Financial instruments evaluated by the model
include commodity futures and options contracts, fixed price swaps, basis swaps
and over-the-counter options. For each of the years ended December 31, 2004 and
2003, value-at-risk reached a high of $8.6 million and $12.8 million,
respectively, and a low of $2.4 million and $2.2 million, respectively.
Value-at-risk as of December 31, 2004, was $8.6 million and averaged $5.1
million for 2004. Value-at-Risk as of December 31, 2003, was $6.2 million and
averaged $5.2 million for 2003.
Our calculated value-at-risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio of
derivatives assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year. In addition, as discussed above, we enter into
these derivatives solely for the purpose of mitigating the risks that accompany
certain of our business activities and, therefore, the change in the market
value of our portfolio of derivatives, with the exception of a minor amount of
hedging inefficiency, is offset by changes in the value of the underlying
physical transactions. For more information on our risk management activities,
see Note 14 to our consolidated financial statements included elsewhere in this
report.
Interest Rate Risk
The market risk inherent in our debt instruments and positions is the
potential change arising from increases or decreases in interest rates as
discussed below.
We utilize both variable rate and fixed rate debt in our financing strategy.
See Note 9 to our consolidated financial statements included elsewhere in this
report for additional information related to our debt instruments. For fixed
rate debt, changes in interest rates generally affect the fair value of the debt
instrument, but not our earnings or cash flows. Conversely, for variable rate
debt, changes in interest rates generally do not impact the fair value of the
debt instrument, but may affect our future earnings and cash flows. We do not
have an obligation to prepay fixed rate debt prior to maturity and, as a result,
interest rate risk and changes in fair value should not have a significant
impact on our fixed rate debt until we would be required to refinance such debt.
As of December 31, 2004 and 2003, the carrying values of our long-term fixed
rate debt were approximately $4,209.6 million and $3,801.7 million,
respectively, compared to fair values of $4,626.9 million and $4,372.3 million,
respectively. Fair values were determined using quoted market prices, where
applicable, or future cash flow discounted at market rates for similar types of
borrowing arrangements. A hypothetical 10% change in the average interest rates
applicable to such debt for 2004 and 2003, respectively, would result in changes
of approximately $161.0 million and $158.6 million, respectively, in the fair
values of these instruments.
The carrying value and fair value of our variable rate debt, including
associated accrued interest and excluding market value of interest rate swaps,
was $495.1 million as of December 31, 2004 and $493.0 million as of December 31,
2003. Fair value was determined using future cash flows discounted based on
market rates for similar types of borrowing arrangements. A hypothetical 10%
change in the average interest rate applicable to our variable rate debt,
including adjustments for notional swap amounts as of December 31, 2004 and
2003, would result in changes of approximately $11.7 million and $10.9 million
in our 2004 and 2003 annualized pre-tax earnings, respectively.
As of December 31, 2004 and 2003, we were a party to interest rate swap
agreements with notional principal amounts of $2.3 billion and $2.1 billion,
respectively. We entered into these agreements for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
A hypothetical 10% change in the average interest rates related to these swaps
would not have a material effect on our annual pre-tax earnings in 2004
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or 2003. We monitor our mix of fixed rate and variable rate debt obligations in
light of changing market conditions and from time to time may alter that mix by,
for example, refinancing balances outstanding under our variable rate debt with
fixed rate debt (or vice versa) or by entering into interest rate swaps or other
interest rate hedging agreements. In general, we attempt to maintain an overall
target mix of approximately 50% fixed rate debt and 50% variable rate debt.
As of December 31, 2004, our cash and investment portfolio did not include
fixed-income securities. Due to the short-term nature of our investment
portfolio, a hypothetical 10% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the
ability to liquidate this portfolio, we do not expect our operating results or
cash flows to be materially affected to any significant degree by the effect of
a sudden change in market interest rates on our investment portfolio.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is included in this report as set
forth in the "Index to Financial Statements" on page 101.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2004, our management, including our Chief Executive Officer
and Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the
possibility of human error and the circumvention or overriding of the controls
and procedures. Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of achieving their control objectives.
Based upon and as of the date of the evaluation, our Chief Executive Officer and
our Chief Financial Officer concluded that the design and operation of our
disclosure controls and procedures were effective in all material respects to
provide reasonable assurance that information required to be disclosed in the
reports we file and submit under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported as and when required.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange
Act Rule 13a-15(f). Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control - Integrated Framework, our
management concluded that our internal control over financial reporting was
effective as of December 31, 2004.
Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included elsewhere in this report.
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Certain businesses we acquired during 2004 were excluded from the scope of our
management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004. These businesses excluded were
North Charleston Bulk Terminal, Kinder Morgan Wink Pipeline, L.P., Kinder Morgan
River Terminals LLC, Charter Products Terminals and Kinder Morgan Fairless Hills
Terminal. These businesses, in the aggregate, constituted .04% of our
consolidated revenues for 2004 and 2.75% of our consolidated assets at December
31, 2004.
Changes in Internal Control Financial Reporting
There has been no change in our internal control over financial reporting
during the fourth quarter of 2004 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
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PART III
Item 10. Directors and Executive Officers of the Registrant.
Directors and Executive Officers of our General Partner and the Delegate
Set forth below is certain information concerning the directors and executive
officers of our general partner and KMR, the delegate of our general partner.
All directors of our general partner are elected annually by, and may be removed
by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of
KMR are elected annually by, and may be removed by, our general partner as the
sole holder of the delegate's voting shares. Kinder Morgan (Delaware), Inc. is a
wholly owned subsidiary of KMI. All officers of the general partner and all
officers of KMR serve at the discretion of the board of directors of our general
partner.
Name Age Position with our General Partner and the Delegate
------------------ --- --------------------------------------------------
Richard D. Kinder....... 60 Director, Chairman, Chief Executive Officer and
President
C. Park Shaper.......... 36 Director, Executive Vice President and Chief
Financial Officer
Edward O. Gaylord....... 73 Director
Gary L. Hultquist....... 61 Director
Perry M. Waughtal....... 69 Director
Thomas A. Bannigan...... 51 Vice President (President, Products Pipelines)
Richard T. Bradley...... 49 Vice President (President, CO2)
David D. Kinder......... 30 Vice President, Corporate Development
Joseph Listengart....... 36 Vice President, General Counsel and Secretary
Deborah A. Macdonald.... 53 Vice President (President, Natural Gas Pipelines)
Jeffrey R. Armstrong.... 36 Vice President (President, Terminals)
James E. Street......... 48 Vice President, Human Resources and Administration
Richard D. Kinder is Director, Chairman, Chief Executive Officer and
President of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as
Director, Chairman and Chief Executive Officer of KMR since its formation in
February 2001. He was elected Director, Chairman and Chief Executive Officer of
KMI in October 1999. He was elected Director, Chairman and Chief Executive
Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected
President of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004. Mr. Kinder is
the uncle of David Kinder, Vice President, Corporate Development of KMR, Kinder
Morgan G.P., Inc. and KMI.
C. Park Shaper is Director, Executive Vice President and Chief Financial
Officer of KMR and Kinder Morgan G.P., Inc. and Executive Vice President and
Chief Financial Officer of KMI. Mr. Shaper was elected Executive Vice President
of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004, and was elected Director
of KMR and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice
President, Treasurer and Chief Financial Officer of KMR upon its formation in
February 2001, and served as Treasurer of KMR from February 2001 to January
2004. He was elected Vice President, Treasurer and Chief Financial Officer of
KMI in January 2000, and served as Treasurer of KMI from January 2000 to January
2004. Mr. Shaper was elected Vice President, Treasurer and Chief Financial
Officer of Kinder Morgan G.P., Inc. in January 2000, and served as Treasurer of
Kinder Morgan G.P., Inc. from January 2000 to January 2004. He received a
Masters in Business Administration degree from the J.L. Kellogg Graduate School
of Management at Northwestern University. Mr. Shaper also has a Bachelor of
Science degree in Industrial Engineering and a Bachelor of Arts degree in
Quantitative Economics from Stanford University.
Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Gaylord was elected Director of KMR upon its formation in February 2001. Mr.
Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since
1989, Mr. Gaylord has been the Chairman of the board of directors of Jacintoport
Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship
channel.
Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Hultquist was elected Director of KMR upon its formation in February 2001. He
was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995,
Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San
Francisco-based strategic and merger advisory firm.
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Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Waughtal was elected Director of KMR upon its formation in February 2001. Mr.
Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since
1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta,
Georgia based real estate investment company. Mr. Waughtal is also a director of
HealthTronics, Inc.
Thomas A. Bannigan is Vice President (President, Products Pipelines) of KMR
and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of
Plantation Pipe Line Company. Mr. Bannigan was elected Vice President
(President, Products Pipelines) of KMR upon its formation in February 2001. He
was elected Vice President (President, Products Pipelines) of Kinder Morgan
G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief
Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan
received his Juris Doctor, cum laude, from Loyola University in 1980 and
received a Bachelors degree from the State University of New York in Buffalo.
Richard T. Bradley is Vice President (President, CO2) of KMR and of Kinder
Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley
was elected Vice President (President, CO2) of KMR upon its formation in
February 2001 and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in
April 2000. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P.
(formerly known as Shell CO2 Company, Ltd.) since March 1998. Mr. Bradley
received a Bachelor of Science in Petroleum Engineering from the University of
Missouri at Rolla.
David D. Kinder is Vice President, Corporate Development of KMR, Kinder
Morgan G.P., Inc. and KMI. Mr. Kinder was elected Vice President, Corporate
Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002. He served
as manager of corporate development for KMI and Kinder Morgan G.P., Inc. from
January 2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors
degree in Finance from Texas Christian University in 1996. Mr. Kinder is the
nephew of Richard D. Kinder.
Joseph Listengart is Vice President, General Counsel and Secretary of KMR,
Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President,
General Counsel and Secretary of KMR upon its formation in February 2001. He was
elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice
President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart
was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been
an employee of Kinder Morgan G.P., Inc. since March 1998. Mr. Listengart
received his Masters in Business Administration from Boston University in
January 1995, his Juris Doctor, magna cum laude, from Boston University in May
1994, and his Bachelor of Arts degree in Economics from Stanford University in
June 1990.
Deborah A. Macdonald is Vice President (President, Natural Gas Pipelines)
of KMR, Kinder Morgan G.P., Inc. and KMI. She was elected as Vice President
(President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI in
June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of
America from October 1999 to March 2003. Ms. Macdonald received her Juris
Doctor, summa cum laude, from Creighton University in May 1980 and received a
Bachelors degree, magna cum laude, from Creighton University in December 1972.
Jeffrey R. Armstrong is Vice President (President, Terminals) of KMR and
Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President,
Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals
LLC from March 1, 2001, when the company was formed via the acquisition of GATX
Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX
Terminals, where he was General Manager of their East Coast operations. He
received his bachelor's degree from the United States Merchant Marine Academy
and an MBA from the University of Notre Dame.
James E. Street is Vice President, Human Resources and Administration of
KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice President,
Human Resources and Administration of KMR upon its formation in February 2001.
He was elected Vice President, Human Resources and Administration of Kinder
Morgan G.P., Inc. and KMI in August 1999. Mr. Street received a Masters of
Business Administration degree from the University of Nebraska at Omaha and a
Bachelor of Science degree from the University of Nebraska at Kearney.
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Corporate Governance
Our limited partnership agreement provides for us to have a general partner
rather than a board of directors. Pursuant to a delegation of control agreement,
our general partner delegated to KMR, to the fullest extent permitted under
Delaware law and our partnership agreement, all of its power and authority to
manage and control our business and affairs, except that KMR cannot take certain
specified actions without the approval of our general partner. Through the
operation of that agreement and our partnership agreement, KMR manages and
controls our business and affairs, and the board of directors of KMR performs
the functions of and acts as our board of directors. Similarly, the standing
committees of KMR's board of directors function as standing committees of our
board. KMR's board of directors is comprised of the same persons who comprise
our general partner's board of directors. References in this report to the board
mean KMR's board, acting as our board of directors, and references to committees
mean KMR's committees, acting as committees of our board of directors.
The board has adopted governance guidelines for the board and charters for the
audit committee, nominating and governance committee and compensation committee.
The governance guidelines and the rules of the New York Stock Exchange require
that a majority of the directors be independent, as described in those
guidelines and rules respectively. To assist in making determinations of
independence, the board has determined that the following categories of
relationships are not material relationships that would cause the affected
director not to be independent:
o If the director was an employee, or had an immediate family member who was
an executive officer, of KMR or us or any of its or our affiliates, but the
employment relationship ended more than three years prior to the date of
determination (or, in the case of employment of a director as an interim
chairman, interim chief executive officer or interim executive officer, such
employment relationship ended by the date of determination);
o If during any twelve month period within the three years prior to the
determination the director received no more than, and has no immediate
family member that received more than, $100,000 in direct compensation from
us or our affiliates, other than (i) director and committee fees and pension
or other forms of deferred compensation for prior service (provided such
compensation is not contingent in any way on continued service), (ii)
compensation received by a director for former service as an interim
chairman, interim chief executive officer or interim executive officer, and
(iii) compensation received by an immediate family member for service as an
employee (other than an executive officer);
o If the director is at the date of determination a current employee, or has
an immediate family member that is at the date of determination a current
executive officer, of another company that has made payments to, or received
payments from, us and our affiliates for property or services in an amount
which, in each of the three fiscal years prior to the date of determination,
was less than the greater of $1.0 million or 2% of such other company's
annual consolidated gross revenues. Contributions to tax-exempt
organizations are not considered payments for purposes of this
determination;
o If the director is also a director, but is not an employee or executive
officer, of our general partner or another affiliate or affiliates of KMR or
us, so long as such director is otherwise independent; and
o If the director beneficially owns less than 10% of each class of voting
securities of us, our general partner, KMR or Kinder Morgan, Inc.
The board has affirmatively determined that Messrs. Gaylord, Hultquist and
Waughtal, who constitute a majority of the directors, are independent as
described in our governance guidelines and the New York Stock Exchange rules.
Each of them meets the standards above and has no other relationship with us. In
conjunction with regular quarterly and special board meetings, these three
non-management directors also meet in executive session without members of
management. In December 2004, Mr. Gaylord was elected for a one year term to
serve as lead director to develop the agendas for and moderate these executive
sessions of independent directors.
We have a separately designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934
comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Waughtal is the
chairman of the audit committee and has been determined by the board to be an
"audit committee financial expert."
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The governance guidelines and our audit committee charter, as well as the rules
of the New York Stock Exchange and the Securities and Exchange Commission,
require that members of the audit committee satisfy independence requirements in
addition to those above. The board has determined that all of the members of the
audit committee are independent as described under the relevant standards.
We have not, nor has our general partner nor KMR made, within the preceding
three years, contributions to any tax-exempt organization in which any of our or
KMR's independent directors serves as an executive officer that in any single
fiscal year exceeded the greater of $1 million or 2% of such tax-exempt
organization's consolidated gross revenues.
On September 3, 2004, our chief executive officer certified to the New York
Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of September 3, 2004, he was not aware of any
violation by us of the New York Stock Exchange's Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public disclosure.
We make available free of charge within the "Investors" information section of
our Internet website, at www.kindermorgan.com, and in print to any unitholder
who requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of
business conduct and ethics (which applies to senior financial and accounting
officers and the chief executive officer, among others). Requests for copies may
be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We
intend to disclose any amendments to our code of business conduct and ethics
that would otherwise be disclosed on Form 8-K and any waiver from a provision of
that code granted to our executive officers or directors that would otherwise be
disclosed on Form 8-K on our Internet website within five business days
following such amendment or waiver. The information contained on or connected to
our Internet website is not incorporated by reference into this Form 10-K and
should not be considered part of this or any other report that we file with or
furnish to the SEC.
You may contact our lead director, the chairpersons of any of the board's
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas
77002, Attention: General Counsel, or by e-mail within the "Contact Us" section
of our Internet website, at www.kindermorgan.com. Your communication should
specify the intended recipient.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Securities Exchange Act of 1934 requires our directors and
officers, and persons who own more than 10% of a registered class of our equity
securities, to file initial reports of ownership and reports of changes in
ownership with the Securities and Exchange Commission. Such persons are required
by SEC regulation to furnish us with copies of all Section 16(a) forms they
file.
Based solely on our review of the copies of such forms furnished to us and
written representations from our executive officers and directors, we believe
that all Section 16(a) filing requirements were met during 2004.
Item 11. Executive Compensation.
As is commonly the case for publicly traded limited partnerships, we have no
officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as
our general partner, is to direct, control and manage all of our activities.
Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has
delegated to KMR the management and control of our business and affairs to the
maximum extent permitted by our partnership agreement and Delaware law, subject
to our general partner's right to approve certain actions by KMR. The executive
officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities
for KMR. Certain of those executive officers, including all of the named
officers below, also serve as executive officers of KMI. All information in this
report with respect to compensation of executive officers describes the total
compensation received by those persons in all capacities for Kinder Morgan G.P.,
Inc., KMR, KMI and their respective affiliates.
88
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Table
Long-Term
Compensation Awards
Annual Compensation -----------------------
------------------------------- Restricted KMI Shares
Stock Underlying All Other
Name and Principal Position Year Salary Bonus(1) Awards(2) Options Compensation(3)
----------------------------- --------- --------- ---------- ------------ ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Richard D. Kinder........... 2004 $ 1 $ -- $ -- -- $ --
Director, Chairman , CEO 2003 1 -- -- -- --
and President 2002 1 -- -- -- --
C. Park Shaper.............. 2004 200,000 975,000 -- -- 8,378
Director, Executive Vice 2003 200,000 875,000 5,918,000 -- 8,378
President and CFO 2002 200,000 950,000 -- 100,000(4) 8,336
Deborah A. Macdonald........ 2004 200,000 975,000 -- -- 8,966
Vice President (President, 2003 200,000 875,000 5,380,000 -- 8,966
Natural Gas Pipelines) 2002 200,000 950,000 -- 50,000(5) 8,966
Joseph Listengart........... 2004 200,000 875,000 -- -- 8,378
Vice President, 2003 200,000 825,000 3,766,000 -- 8,378
General Counsel and 2002 200,000 950,000 -- -- 8,336
Secretary
Richard T. Bradley.......... 2004 200,000 560,000 -- -- 8,630
Vice President (President, 2003 200,000 525,000 2,152,000 -- 8,606
CO2) 2002 200,000 500,000 -- -- 8,606
</TABLE>
----------
(1) Amounts earned in year shown but paid the following year.
(2) Represent shares of restricted KMI stock awarded in 2003. The awards were
issued under a shareholder approved plan. For the 2003 awards, value
computed as the number of shares awarded times the closing price on date of
grant ($53.80 at July 16, 2003). Twenty-five percent of the shares in each
grant vest on the third anniversary after the date of grant and the
remaining seventy-five percent of the shares in each grant vest on the
fifth anniversary after the date of grant. To vest, we and/or KMI must also
achieve one of the following performance hurdles during the vesting period:
(i) KMI must earn $3.70 per share in any fiscal year; (ii) we must
distribute $2.72 over four consecutive quarters; (iii) we and KMI must fund
at least one year's annual incentive program; or (iv) KMI's stock price
must average over $60.00 per share during any consecutive 30-day period.
All of these hurdles have been met. The 2003 awards were long-term equity
compensation for our current senior management through July 2008, and
neither we nor KMI intend to make further restricted stock awards or other
long-term equity grants to them before that date. The holders of the
restricted stock awards are eligible to vote and to receive dividends
declared on such shares.
(3) Amounts represent value of contributions to the Kinder Morgan Savings Plan
(a 401(k) plan), value of group-term life insurance exceeding $50,000 and
taxable parking subsidy.
(4) The 100,000 options to purchase KMI shares were granted on January 16, 2002
with an exercise price of $56.99 per share and vest at the rate of
twenty-five percent on each of the first four anniversaries after the date
of grant.
(5) The 50,000 options to purchase KMI shares were granted on January 16, 2002
with an exercise price of $56.99 per share and vest at the rate of
twenty-five percent on each of the first four anniversaries after the date
of grant.
Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined
contribution 401(k) plan. The plan permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of
base compensation, on a pre-tax basis, into participant accounts. In addition to
a mandatory contribution equal to 4% of base compensation per year for most plan
participants, our general partner may make discretionary contributions in years
when specific performance objectives are met. Certain employees' contributions
are based on collective bargaining agreements. The mandatory contributions are
made each pay period on behalf of each eligible employee. Any discretionary
contributions are made during the first quarter following the performance year.
All employer contributions, including discretionary contributions, are in the
form of KMI stock that is immediately convertible into other available
investment vehicles at the employee's discretion. During the first quarter of
2005, we will not make any discretionary contributions to individual accounts
for 2004.
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<PAGE>
For employees hired on or prior to December 31, 2004, all contributions,
together with earnings thereon, are immediately vested and not subject to
forfeiture. Employer contributions for employees hired on or after January 1,
2005 will vest on the second anniversary of the date of hire. Participants may
direct the investment of their contributions into a variety of investments. Plan
assets are held and distributed pursuant to a trust agreement. Because levels of
future compensation, participant contributions and investment yields cannot be
reliably predicted over the span of time contemplated by a plan of this nature,
it is impractical to estimate the annual benefits payable at retirement to the
individuals listed in the Summary Compensation Table above.
At its July 2004 meeting, the compensation committee of the KMI board of
directors approved that contingent upon its approval at its July 2005 meeting,
each eligible employee will receive an additional 1% company contribution based
on eligible base pay to his or her Savings Plan account each pay period
beginning with the first pay period after the July 2005 Committee meeting. The
1% contribution will be in the form of KMI common stock (the same as the current
4% contribution). The 1% contribution will be in addition to, and does not
change or otherwise impact, the annual 4% contribution that eligible employees
currently receive. It may be converted to any other Savings Plan investment fund
at any time and it will vest on the second anniversary of the employee's date of
hire. Since this additional 1% company contribution is discretionary,
compensation committee approval will be required annually for each contribution.
Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key
personnel are eligible to receive grants of options to acquire common units. The
total number of common units authorized under the option plan is 500,000. None
of the options granted under the option plan may be "incentive stock options"
under Section 422 of the Internal Revenue Code. If an option expires without
being exercised, the number of common units covered by such option will be
available for a future award. The exercise price for an option may not be less
than the fair market value of a common unit on the date of grant. KMR's
compensation committee administers the option plan, and the plan has a
termination date of March 5, 2008.
No individual employee may be granted options for more than 20,000 common
units in any year. KMR's compensation committee will determine the duration and
vesting of the options to employees at the time of grant. As of December 31,
2004, options to purchase 95,400 common units are currently outstanding and held
by 30 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder
Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will
vest on the first anniversary of the date of grant and twenty percent on each of
the next three anniversaries. The options expire seven years from the date of
grant. As of December 31, 2004, all 95,400 outstanding options were fully
vested.
The option plan also granted to each of our non-employee directors an option
to purchase 10,000 common units at an exercise price equal to the fair market
value of the common units at the end of the trading day on such date. Under this
provision, as of December 31, 2004, options to purchase 20,000 common units are
currently outstanding and held by two of Kinder Morgan G.P., Inc.'s three
non-employee directors. Forty percent of all such options will vest on the first
anniversary of the date of grant and twenty percent on each of the next three
anniversaries. The non-employee director options will expire seven years from
the date of grant. As of December 31, 2004, all 20,000 outstanding options were
fully vested.
No options to purchase common units were granted during 2004 to any of the
individuals named in the Summary Compensation Table above. The following table
sets forth certain information as of December 31, 2004 and for the fiscal year
then ended with respect to common unit options previously granted to the
individuals named in the Summary Compensation Table above. Mr. Listengart is the
only person named in the Summary Compensation Table who was granted common unit
options. No common unit options were granted at an option price below the fair
market value on the date of grant.
<TABLE>
<CAPTION>
Aggregated Common Unit Option Exercises in 2004 and 2004 Year-End Common Unit Option Values
Number of Units Value of Unexercised
Underlying Unexercised In-the-Money Options
Units Acquired Value Options at 2004 Year-End At 2004 Year-End
--------------------------- ----------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
------------------ -------------- ---------- ------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C> <C>
Joseph Listengart.... 10,000 $ 283,667 -- -- -- --
</TABLE>
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<PAGE>
KMI Stock Plan. Under KMI's stock plan, employees of KMI and its affiliates,
including employees of KMI's direct and indirect subsidiaries, like KMGP
Services Company, Inc., are eligible to receive grants of restricted KMI stock
and grants of options to acquire shares of common stock of KMI. The compensation
committee of KMI's board of directors administers this plan. The primary purpose
for granting restricted KMI stock and KMI stock options under this plan to
employees of KMI, KMGP Services Company, Inc. and our subsidiaries is to provide
them with an incentive to increase the value of the common stock of KMI. A
secondary purpose of the grants is to provide compensation to those employees
for services rendered to our subsidiaries and us. During 2004, none of the
persons named in the Summary Compensation Table above were granted KMI stock
options.
<TABLE>
<CAPTION>
Number of Shares Value of Unexercised
Underlying Unexercised In-the-Money Options
Options at 2004 Year-End at 2004 Year-End(1)
Shares Acquired Value --------------------------- ----------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
-------------------- --------------- ---------- --------------------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
C. Park Shaper.............. - $ - 170,000 50,000 $5,984,475 $807,000
Deborah A. Macdonald........ 50,000 $1,900,674 25,000 25,000 $ 403,500 $403,500
Joseph Listengart........... 50,000 $1,843,154 56,300 - $2,612,382 -
Richard T. Bradley.......... 40,000 $1,284,830 25,000 - $1,057,938 -
</TABLE>
----------
(1) Calculated on the basis of the fair market value of the underlying shares at
year-end, minus the exercise price.
Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and
KMI are also eligible to participate in a Cash Balance Retirement Plan. Certain
employees continue to accrue benefits through a career-pay formula,
"grandfathered" according to age and years of service on December 31, 2000, or
collective bargaining arrangements. All other employees accrue benefits through
a personal retirement account in the Cash Balance Retirement Plan. Employees
with prior service and not grandfathered converted to the Cash Balance
Retirement Plan on January 1, 2001, and were credited with the current fair
value of any benefits they had previously accrued through the defined benefit
plan. Under the plan, we make contributions on behalf of participating employees
equal to 3% of eligible compensation every pay period. In addition,
discretionary contributions are made to the plan based on our and KMI's
performance. No discretionary contributions were made for 2004 performance.
Interest is credited to the personal retirement accounts at the 30-year U.S.
Treasury bond rate, or an approved substitute, in effect each year. Employees
become fully vested in the plan after five years, and they may take a lump sum
distribution upon termination of employment or retirement.
The following table sets forth the estimated annual benefits payable as of
December 31, 2004, under normal retirement at age sixty-five, assuming current
remuneration levels without any salary projection, and participation until
normal retirement at age sixty-five, with respect to the named executive
officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan.
These benefits are subject to federal and state income taxes, where applicable,
but are not subject to deduction for social security or other offset amounts.
<TABLE>
<CAPTION>
Estimated Current Estimated
Current Credited Yrs Compensation Annual Benefit
Credited Yrs of Service Age as of Covered by Payable Upon
Name Of Service at Age 65 Jan. 1, 2005 Plans Retirement (1)
---- ------------ ------------ ------------ ------------ --------------
<S> <C> <C> <C> <C> <C>
Richard D. Kinder......... 4 8.8 60.2 $ 1 $ -
C. Park Shaper............ 4 32.7 36.4 200,000 62,363
Joseph Listengart......... 4 32.5 36.6 200,000 61,608
Deborah A. Macdonald...... 4 15.9 53.1 200,000 15,763
Richard T. Bradley........ 4 19.8 49.2 200,000 22,727
</TABLE>
----------
(1) The estimated annual benefits payable are based on the straight-life annuity
form.
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<PAGE>
2000 Annual Incentive Plan. Effective January 20, 2000, KMI established the
2000 Annual Incentive Plan of Kinder Morgan, Inc. The plan was established, in
part, to enable the portion of an officer's or other employee's annual bonus
based on objective performance criteria to qualify as "qualified performance-
based compensation" under the Internal Revenue Code. "Qualified performance-
based compensation" compensation is deductible for tax purposes. The plan
permits annual bonuses to be paid to KMI's officers and other employees and
employees of KMI's subsidiaries based on their individual performance, KMI's
performance and the performance of KMI's subsidiaries. The plan is administered
by the compensation committee of KMI's board of directors. Under the plan, at or
before the start of each calendar year, the compensation committee establishes
written performance objectives. The performance objectives are based on one or
more criteria set forth in the plan. The compensation committee may specify a
minimum acceptable level of achievement of each performance objective below
which no bonus is payable with respect to that objective. The maximum payout to
any individual under the plan in any year is $1.5 million, and the compensation
committee has the discretion to reduce the bonus amount in any performance
period. The cash bonuses set forth in the Summary Compensation Table above were
paid under the plan. Awards may be granted under the plan for calendar years
2000 through 2005.
Compensation Committee Interlocks and Insider Participation. As disclosed
above, the compensation committee of KMR functions as our compensation
committee. KMR's compensation committee, comprised of Mr. Edward O. Gaylord, Mr.
Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions
regarding the executive officers of our general partner and its delegate, KMR.
Mr. Richard D. Kinder and Mr. James E. Street, who are executive officers of
KMR, participate in the deliberations of the KMR compensation committee
concerning executive officer compensation. Mr. Kinder receives $1.00 annually in
total compensation for services to KMI, KMR and our general partner.
Directors Fees. Our Directors' Unit Appreciation Rights Plan, as discussed
below, served as partial compensation for non-employee directors for 2004. In
addition to the awards provided by this plan, each non-employee director
received additional compensation of $10,000 in 2004, paid $2,500 per quarter.
Mr. Edward O. Gaylord, as chairman of the KMR audit committee, received
additional compensation in the amount of $10,000, paid $2,500 per quarter. Mr.
Perry M. Waughtal, appointed as lead director in October 2003 by KMR and who
served as lead director until December 2004, received additional compensation in
the amount of $25,000, paid $10,000 in the first quarter and $5,000 in each of
the last three quarters. In addition, directors are reimbursed for reasonable
expenses in connection with board meetings.
In January 2005, KMR terminated the Directors' Unit Appreciation Rights Plan
and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan for Non-Employee Directors, as discussed below, to compensate non-employee
directors for 2005.
Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's
compensation committee established our Directors' Unit Appreciation Rights Plan.
Pursuant to this plan, each of KMR's three non-employee directors was eligible
to receive common unit appreciation rights. Upon the exercise of unit
appreciation rights, we will pay, within thirty days of the exercise date, the
participant an amount of cash equal to the excess, if any, of the aggregate fair
market value of the unit appreciation rights exercised as of the exercise date
over the aggregate award price of the rights exercised. The fair market value of
one unit appreciation right as of the exercise date will be equal to the closing
price of one common unit on the New York Stock Exchange on that date. The award
price of one unit appreciation right will be equal to the closing price of one
common unit on the New York Stock Exchange on the date of grant. Proceeds, if
any, from the exercise of a unit appreciation right granted under the plan will
be payable only in cash (that is, no exercise will result in the issuance of
additional common units) and will be evidenced by a unit appreciation rights
agreement.
All unit appreciation rights granted vest on the six-month anniversary of the
date of grant. If a unit appreciation right is not exercised in the ten year
period following the date of grant, the unit appreciation right will expire and
not be exercisable after the end of such period. In addition, if a participant
ceases to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised.
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<PAGE>
On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights were granted to each of KMR's three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004. As of
December 31, 2004, 52,500 unit appreciation rights had been granted. No unit
appreciation rights were exercised during 2004. During the first board meeting
of 2005, the plan was terminated and replaced by the Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors;
however, all unexercised awards made under the plan remain outstanding.
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors. On January 18, 2005, KMR's compensation committee
established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan to compensate KMR's non-employee directors for 2005. The plan is
administered by KMR's compensation committee and KMR's board has sole discretion
to terminate the plan at any time. The primary purpose of this plan was to
promote our interests and the interests of our unitholders by aligning the
compensation of the non-employee members of the board of directors of KMR with
unitholders' interests. Further, since KMR's success is dependent on its
operation and management of our business and our resulting performance, the plan
is expected to align the compensation of the non-employee members of the board
with the interests of KMR's shareholders.
The plan recognizes that the compensation to be paid to each non-employee
director is fixed by the KMR board, generally annually, and that the
compensation is expected to include an annual retainer payable in cash and other
cash compensation. Pursuant to the plan, in lieu of receiving the other cash
compensation, each non-employee director may elect to receive common units. Each
election shall be generally at or around the first board meeting in January of
each calendar year and will be effective for the entire calendar year. The
initial election under this plan was made effective January 20, 2005. A
non-employee director may make a new election each calendar year. The total
number of common units authorized under this compensation plan is 100,000.
Each annual election shall be evidenced by an agreement, the Common Unit
Compensation Agreement, between us and each non-employee director, and this
agreement will contain the terms and conditions of each award. Pursuant to this
agreement, all common units issued under this plan are subject to forfeiture
restrictions that expire six months from the date of issuance. Until the
forfeiture restrictions lapse, common units issued under the plan may not be
sold, assigned, transferred, exchanged, or pledged by a non-employee director.
In the event the director's service as a director of KMR is terminated prior to
the lapse of the forfeiture restriction either for cause, or voluntary
resignation, each director shall, for no consideration, forfeit to us all common
units to the extent then subject to the forfeiture restrictions. Common units
with respect to which forfeiture restrictions have lapsed shall cease to be
subject to any forfeiture restrictions, and we will provide each director a
certificate representing the units as to which the forfeiture restrictions have
lapsed. In addition, each non-employee director shall have the right to receive
distributions with respect to the common units awarded to him under the plan, to
vote such common units and to enjoy all other unitholder rights, including
during the period prior to the lapse of the forfeiture restrictions.
The number of common units to be issued to a non-employee director electing to
receive the other cash compensation in the form of common units will equal such
other cash compensation awarded, divided by the closing price of the common
units on the New York Stock Exchange on the day the cash compensation is awarded
(such price, the fair market value), rounded down to the nearest 50 common
units. The common units will be issuable as specified in the Common Unit
Compensation Agreement. A non-employee director electing to receive the other
cash compensation in the form of common units will receive cash equal to the
difference between (i) the other cash compensation awarded to such non-employee
director and (ii) the number of common units to be issued to such non-employee
director multiplied by the fair market value of a common unit. This cash payment
shall be payable in four equal installments (together with the annual cash
retainer) generally around March 31, June 30, September 30 and December 31 of
the calendar year in which such cash compensation is awarded.
On January 18, 2005, the date of adoption of the plan, each of KMR's three
non-employee directors was awarded a cash retainer of $40,000 that will be paid
quarterly during 2005, and other cash compensation of $79,750. Effective January
20, 2005, each non-employe director elected to receive the other cash
compensation of $79,750 in the form of our common units and was issued 1,750
common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other
cash compensation that did not equate to a whole
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<PAGE>
common unit, based on the January 18, 2005 $45.55 closing price, will be paid to
each of the non-employee directors as described above. No other compensation is
to be paid to the non-employee directors during 2005.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth information as of January 31, 2005, regarding
(a) the beneficial ownership of (i) our common and Class B units, (ii) the
common stock of KMI, the parent company of our general partner, and (iii) KMR
shares by all directors of our general partner and KMR, its delegate, by each of
the named executive officers and by all directors and executive officers as a
group and (b) the beneficial ownership of our common and Class B units or shares
of KMR by all persons known by our general partner to own beneficially more than
5% of our common and Class B units and KMR shares. Unless otherwise noted, the
address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002.
<TABLE>
<CAPTION>
Kinder Morgan
Common Units Class B Units Management Shares KMI Voting Stock
---------------------- --------------------- --------------------- -----------------------
Number Percent Number Percent Number Percent Number Percent
of Units(2) of Class Of Units(3) of Class of Shares(4) of Class of Shares(5) of Class
----------- -------- ----------- -------- ------------ -------- ------------ --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Richard D. Kinder(6)........... 315,979 * -- -- 47,379 * 23,995,415 19.45%
C. Park Shaper(7).............. 4,000 * -- -- 2,534 * 326,808 *
Edward O. Gaylord(8)........... 34,750 * -- -- -- -- 2,000 *
Gary L. Hultquist(9)........... 11,750 * -- -- -- -- -- --
Perry M. Waughtal(10).......... 39,050 * -- -- 37,594 * 50,000 *
Joseph Listengart(11).......... 4,198 * -- -- -- -- 140,106 *
Deborah A. Macdonald(12)....... -- -- -- -- -- -- 121,374 *
Richard T. Bradley(13)......... -- -- -- -- -- -- 71,314 *
Directors and Executive Officers
as a group (12 persons)(14). 427,006 * -- -- 90,607 * 25,033,714 20.29%
Kinder Morgan, Inc.(15)........ 14,355,735 9.73% 5,313,400 100.00% 13,293,298 24.55% -- --
Fayez Sarofim(16).............. 7,888,871 5.35% -- -- -- -- -- --
Capital Group International, -- -- -- -- 4,970,550 9.18% -- --
Inc.(17).......................
OppenheimerFunds, Inc.(18)..... -- -- -- -- 4,822,317 8.90% -- --
Kayne Anderson Capital Advisors,
L.P.(19).................... -- -- -- -- 3,816,642 7.05% -- --
</TABLE>
----------
* Less than 1%.
(1) Except as noted otherwise, all units, KMR shares and KMI shares involve sole
voting power and sole investment power. For KMR, see note (4). On January
18, 2005, KMR's board of directors initiated a rule requiring each director
to own a minimum of 10,000 common units, KMR shares, or a combination
thereof. If a director does not already own the minimum number of required
securities, the director will have six years to acquire such securities.
(2) As of January 31, 2005, we had 147,555,658 common units issued and
outstanding.
(3) As of January 31, 2005, we had 5,313,400 Class B units issued and
outstanding.
(4) Represent the limited liability company shares of KMR. As of January 31,
2005, there were 54,157,641 issued and outstanding KMR shares, including two
voting shares owned by our general partner. In all cases, our i-units will
be voted in proportion to the affirmative and negative votes, abstentions
and non-votes of owners of KMR shares. Through the provisions in our
partnership agreement and KMR's limited liability company agreement, the
number of outstanding KMR shares, including voting shares owned by our
general partner, and the number of our i-units will at all times be equal.
(5) As of January 31, 2005, KMI had a total of 123,378,197 shares of issued and
outstanding voting common stock, which excludes 11,076,901 shares held in
treasury.
(6) Includes (a) 7,879 common units owned by Mr. Kinder's spouse, (b) 5,173 KMI
shares held by Mr. Kinder's spouse and (c) 250 KMI shares held by Mr. Kinder
in a custodial account for his nephew. Mr. Kinder disclaims any and all
beneficial or pecuniary interest in these units and shares.
(7) Includes options to purchase 195,000 KMI shares exercisable within 60 days
of January 31, 2005, and includes 112,500 shares of restricted KMI stock.
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(8) Includes 1,750 restricted common units.
(9) Includes options to purchase 10,000 common units exercisable within 60 days
of January 31, 2005, and includes 1,750 restricted common units.
(10) Includes options to purchase 10,000 common units exercisable within 60 days
of January 31, 2005, and includes 1,750 restricted common units.
(11) Includes options to purchase 56,300 KMI shares exercisable within 60 days
of January 31, 2005, and includes 72,500 shares of restricted KMI stock.
(12) Includes 102,500 shares of restricted KMI stock.
(13) Includes options to purchase 20,000 KMI shares exercisable within 60 days
of January 31, 2005, and includes 41,250 shares of restricted KMI stock.
(14) Includes options to purchase 24,000 common units and 433,300 KMI shares
exercisable within 60 days of January 31, 2005, and includes 5,250
restricted common units and 467,500 shares of restricted KMI stock.
(15) Includes common units owned by KMI and its consolidated subsidiaries,
including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(16) As reported on the Schedule 13G/A filed February 11, 2005 by Fayez Sarofim
& Co. and Fayez Sarofim. Mr. Sarofim reports that in regard to our common
units, he has sole voting power over 2,300,000 common units, shared voting
power over 4,242,612 common units, sole disposition power over 2,300,000
common units and shared disposition power over 5,588,871 common units. Mr.
Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010.
(17) As reported on the Schedule 13G/A filed February 14, 2005 by Capital Group
International, Inc. and Capital Guardian Trust Company. Capital Group
International, Inc. and Capital Guardian Trust Company report that in
regard to KMR shares, they have sole voting power over 3,913,560 shares,
shared voting power over 0 shares, sole disposition power over 4,970,550
shares and shared disposition power over 0 shares. Capital Group
International, Inc.'s and Capital Guardian Trust Company's address is 11100
Santa Monica Blvd., Los Angeles, California 90025.
(18) As reported on the Schedule 13G/A filed February 11, 2005 by
OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund.
OppenheimerFunds, Inc. reports that in regard to KMR shares, it has sole
voting power over 0 shares, shared voting power over 0 shares, sole
disposition power over 0 shares and shared disposition power over 4,822,317
shares. Of these 4,822,317 KMR shares, Oppenheimer Capital Income Fund has
sole voting power over 3,232,500 shares, shared voting power over 0 shares,
sole disposition power over 0 shares and shared disposition power over
3,232,500 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street,
11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's
address is 6803 Tucson Way, Centennial, Colorado 80112.
(19) As reported on the Schedule 13G filed February 11, 2005 by Kayne Anderson
Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital
Advisors, L.P. reports that in regard to KMR shares, it has sole voting
power over 0 shares, shared voting power over 3,815,712 shares, sole
disposition power over 0 shares and shared disposition power over 3,815,712
shares. Mr. Anderson reports that in regard to KMR shares, he has sole
voting power over 930 shares, shared voting power over 3,815,712 shares,
sole disposition power over 930 shares and shared disposition power over
3,815,712 shares. Kayne Anderson Capital Advisors, L.P. and Richard A.
Kayne's address is 1800 Avenue of the Stars, Second Floor, Los Angeles,
California 90067.
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation
plans as of January 31, 2005. Specifically, the table refers to information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation") as of January 31, 2005.
95
<PAGE>
<TABLE>
<CAPTION>
Number of securities
remaining available for
Number of securities Weighted average future issuance under equity
to be issued upon exercise exercise price compensation plans
of outstanding options, of outstanding options, (excluding securities reflected
warrants and rights warrants and rights In column (a))
Plan category (a) (b) (c)
--------------------------------- -------------------------- ----------------------- -------------------------------
<S> <C> <C> <C>
Equity compensation plans
approved by security holders - - -
Equity compensation plans
not approved by security holders 95,900 $18.0755 55,400
------ ------
Total 95,900 55,400
====== ======
</TABLE>
Item 13. Certain Relationships and Related Transactions.
See Note 12 of the notes to our consolidated financial statements included
elsewhere in this report.
Item 14. Principal Accounting Fees and Services
The following sets forth fees billed for the audit and other services provided
by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2004 and
2003 (in dollars):
Year Ended December 31,
-----------------------
2004 2003
---------- ----------
Audit fees(1).............$2,147,000 $1,079,092
Audit-Related fees(2)..... 34,000 -
Tax fees(3)............... 1,994,956 1,347,903
--------- ---------
Total...................$4,175,956 $2,426,995
========== ==========
----------
(1) Includes fees for audit of annual financial statements, reviews of the
related quarterly financial statements, and reviews of documents filed with
the Securities and Exchange Commission.
(2) Includes fees for assurance and related services that are reasonably related
to the performance of the audit or review of our financial statements.
(3) Includes fees related to professional services for tax compliance, tax
advice and tax planning.
All services rendered by PricewaterhouseCoopers LLP are permissible under
applicable laws and regulations, and are pre-approved by the audit committee of
KMR and our general partner. Pursuant to the charter of the audit committee of
KMR, the delegate of our general partner, the committee's primary purposes
include the following:
o to select, appoint, engage, oversee, retain, evaluate and terminate our
external auditors;
o to pre-approve all audit and non-audit services, including tax services, to
be provided, consistent with all applicable laws, to us by our external
auditors; and
o to establish the fees and other compensation to be paid to our external
auditors.
Furthermore, the audit committee will review the external auditors' proposed
audit scope and approach as well as the performance of the external auditors. It
also has direct responsibility for and sole authority to resolve any
disagreements between our management and our external auditors regarding
financial reporting, will regularly review with the external auditors any
problems or difficulties the auditors encountered in the course of their audit
work, and will, at least annually, use its reasonable efforts to obtain and
review a report from the external auditors addressing the following (among other
items):
o the auditors' internal quality-control procedures;
96
<PAGE>
o any material issues raised by the most recent internal quality-control
review, or peer review, of the external auditors;
o the independence of the external auditors; and
o the aggregate fees billed by our external auditors for each of the previous
two fiscal years.
97
<PAGE>
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page 101.
(a)(3) Exhibits
*3.1-- Third Amended and Restated Agreement of Limited Partnership of Kinder
Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan
Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001,
filed on August 9, 2001).
*3.2-- Amendment No. 1 dated November 19, 2004 to Third Amended and Restated
Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P.
(filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K
filed November 22, 2004).
*4.1-- Specimen Certificate evidencing Common Units representing Limited Partner
Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan
Energy Partners, L.P. Registration Statement on Form S-4, File No.
333-44519, filed on February 4, 1998).
*4.2-- Indenture dated as of January 29, 1999 among Kinder Morgan Energy
Partners, L.P., the guarantors listed on the signature page thereto and
U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt
Securities (filed as Exhibit 4.1 to the Partnership's Current Report on
Form 8-K filed February 16, 1999, File No. 1-11234 (the "February 16,
1999 Form 8-K")).
*4.3-- First Supplemental Indenture dated as of January 29, 1999 among Kinder
Morgan Energy Partners, L.P., the subsidiary guarantors listed on the
signature page thereto and U.S. Trust Company of Texas, N.A., as trustee,
relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009
(filed as Exhibit 4.2 to the February 16, 1999 Form 8-K).
*4.4-- Second Supplemental Indenture dated as of September 30, 1999 among
Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas,
N.A., as trustee, relating to release of subsidiary guarantors under the
$250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit
4.4 to the Partnership's Form 10-Q for the quarter ended September 30,
1999 (the "1999 Third Quarter Form 10-Q")).
*4.5-- Indenture dated March 22, 2000 between Kinder Morgan Energy Partners,
L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.1 to
Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4
(File No. 333-35112) filed on April 19, 2000 (the "April 2000 Form
S-4")).
*4.6-- Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to
the April 2000 Form S-4).
*4.7-- Indenture dated November 8, 2000 between Kinder Morgan Energy
Partners, L.P. and First Union National Bank, as Trustee (filed as
Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001).
*4.8-- Form of 7.50% Notes due November 1, 2010 (contained in the Indenture
filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K
for 2001).
*4.9-- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners
and First Union National Bank, as trustee, relating to Senior Debt
Securities (including form of Senior Debt Securities) (filed as Exhibit
4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000).
*4.10-- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners
and First Union National Bank, as trustee, relating to Subordinated Debt
Securities (including form of Subordinated Debt Securities) (filed as
Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000).
*4.11-- Certificate of Vice President and Chief Financial Officer of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes
due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on
March 14, 2001).
*4.12-- Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed
as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on
March 14, 2001).
*4.13-- Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed
as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on
March 14, 2001).
98
<PAGE>
*4.14-- Certificate of Vice President and Chief Financial Officer of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes
due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.15-- Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed
as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.16-- Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed
as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.17-- Indenture dated August 19, 2002 between Kinder Morgan Energy Partners,
L.P. and Wachovia Bank, National Association, as Trustee (filed as
Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration
Statement on Form S-4 (File No. 333-100346) filed on October 4, 2002
(the "October 4, 2002 Form S-4")).
*4.18-- First Supplemental Indenture to Indenture dated August 19, 2002, dated
August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia
Bank, National Association, as Trustee (filed as Exhibit 4.2 to the
October 4, 2002 Form S-4).
*4.19-- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture
filed as Exhibit 4.1 to the October 4, 2002 Form S-4).
*4.20-- Senior Indenture dated January 31, 2003 between Kinder Morgan Energy
Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit
4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on
Form S-3 (File No. 333-102961) filed on February 4, 2003 (the "February
4, 2003 Form S-3")).
*4.21-- Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included
in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4,
2003 Form S-3).
*4.22-- Subordinated Indenture dated January 31, 2003 between Kinder Morgan
Energy Partners, L.P. and Wachovia Bank, National Association (filed as
Exhibit 4.4 to the February 4, 2003 Form S-3).
*4.23-- Form of Subordinated Note of Kinder Morgan Energy Partners, L.P.
(included in the Form of Subordinated Indenture filed as Exhibit 4.4 to
the February 4, 2003 Form S-3).
*4.24-- Certificate of Vice President, Treasurer and Chief Financial Officer
and Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
Energy Partners, L.P. establishing the terms of the 5.00% Notes due
December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy
Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*4.25-- Specimen of 5.00% Notes due December 15, 2013 in book-entry form
(filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form 10-K
for 2003 filed March 5, 2004).
4.26-- Specimen of 5.125% Notes due November 15, 2014 in book-entry form.
4.27-- Certificate of Executive Vice President and Chief Financial Officer and
Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
Energy Partners, L.P. establishing the terms of the 5.125% Notes
due November 15, 2014.
4.28-- Certain instruments with respect to long-term debt of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries which relate to
debt that does not exceed 10% of the total assets of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries are omitted
pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R.
sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to
furnish supplementally to the Securities and Exchange Commission a copy
of each such instrument upon request.
*10.1-- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as
Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K,
File No. 1-11234).
*10.2-- Delegation of Control Agreement among Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its
operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan
Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001).
*10.3-- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights
Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P.
Form 10-K for 2003 filed March 5, 2004).
*10.4-- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit
Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan
Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
99
<PAGE>
*10.5-- Resignation and Non-Compete agreement dated July 21, 2004
between KMGP Services, Inc. and Michael C. Morgan,
President of Kinder Morgan, Inc., Kinder Morgan G.P., Inc.
and Kinder Morgan Management, LLC (filed as Exhibit 10.1 to
the Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended June 30, 2004, filed on August 5, 2004).
*10.6-- 5-Year Credit Agreement dated as of August 18, 2004 among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
Bank, National Association as Administrative Agent (filed as Exhibit
10.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter
ended September 30, 2004, filed November 2, 2004).
*10.7-- Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy
Partners, L.P. Form 8-K filed January 21, 2005).
*10.8-- Form of Common Unit Compensation Agreement entered into with
Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy
Partners, L.P. Form 8-K filed January 21, 2005).
11.1-- Statement re: computation of per share earnings.
21.1-- List of Subsidiaries.
23.1-- Consent of PricewaterhouseCoopers LLP.
23.2-- Consent of Netherland, Sewell and Associates, Inc.
31.1-- Certification by CEO pursuant to Rule 13a-14(a) or
15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2-- Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
32.1-- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2-- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
----------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith, except as noted otherwise.
100
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Page
Number
------
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm................. 102
Consolidated Statements of Income for the years ended December 31,
2004, 2003, and 2002.................................................... 103
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2004, 2003, and 2002....................................... 104
Consolidated Balance Sheets as of December 31, 2004 and 2003............ 105
Consolidated Statements of Cash Flows for the years ended December
31, 2004, 2003, and 2002................................................ 106
Consolidated Statements of Partners' Capital for the years ended
December 31, 2004, 2003, and 2002....................................... 107
Notes to Consolidated Financial Statements.............................. 108
101
<PAGE>
Report of Independent Registered Public Accounting Firm
To the Partners of
Kinder Morgan Energy Partners, L.P.
We have completed an integrated audit of Kinder Morgan Energy Partners, L.P.'s
(the Partnership) 2004 consolidated financial statements and of its internal
control over financial reporting as of December 31, 2004 and audits of its 2003
and 2002 consolidated financial statements in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Our opinions,
based on our audits, are presented below.
Consolidated financial statements
---------------------------------
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries at December 31, 2004 and 2003,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2004 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit of financial statements includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 4 to the consolidated financial statements, the Partnership
changed its method of accounting for asset retirement obligations effective
January 1, 2003.
As discussed in Note 8 to the consolidated financial statements, the Partnership
changed its method of accounting for goodwill and other intangible assets
effective January 1, 2002.
Internal control over financial reporting
-----------------------------------------
Also, in our opinion, management's assessment, included in Management's Report
on Internal Control Over Financial Reporting appearing under Item 9A, that the
Partnership maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Partnership maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control --
Integrated Framework issued by the COSO. The Partnership's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express opinions on management's assessment
and on the effectiveness of the Partnership's internal control over financial
reporting based on our audit. We conducted our audit of internal control over
financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
As described in Management's Report on Internal Control Over Financial
Reporting, management has excluded North Charleston Bulk Terminal, Kinder Morgan
Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products
Terminals and Kinder Morgan Fairless Hills Terminal from its assessment of
internal control over financial reporting as of December 31, 2004 because these
businesses were acquired by the Partnership in purchase business combinations
during 2004. We have also excluded North Charleston Bulk Terminal, Kinder Morgan
Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products
Terminals and Kinder Morgan Fairless Hills Terminal from our audit of internal
control over financial reporting. These businesses, in the aggregate,
constituted .04% of the Partnership's consolidated revenues for 2004 and 2.75%
of the Partnership's consolidated assets at December 31, 2004.
PricewaterhouseCoopers LLP
Houston, Texas
March 3, 2004
102
<PAGE>
<TABLE>
<CAPTION>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
--------------------------------------
2004 2003 2002
---------- ---------- ----------
(In thousands except per unit amounts)
Revenues
<S> <C> <C> <C>
Natural gas sales............................................... $5,803,065 $4,889,235 $2,740,518
Services........................................................ 1,571,504 1,377,745 1,272,640
Product sales and other......................................... 558,292 357,342 223,899
---------- ---------- ----------
7,932,861 6,624,322 4,237,057
---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of sales.......................... 5,767,169 4,880,118 2,704,295
Operations and maintenance...................................... 499,714 397,723 376,479
Fuel and power.................................................. 151,480 108,112 86,413
Depreciation and amortization................................... 288,626 219,032 172,041
General and administrative...................................... 170,507 150,435 122,205
Taxes, other than income taxes.................................. 81,369 62,213 51,326
---------- ---------- ----------
6,958,865 5,817,633 3,512,759
---------- ---------- ----------
Operating Income.................................................. 973,996 806,689 724,298
Other Income (Expense)
Earnings from equity investments................................ 83,190 92,199 89,258
Amortization of excess cost of equity investments............... (5,575) (5,575) (5,575)
Interest, net................................................... (192,882) (181,357) (176,460)
Other, net...................................................... 2,254 7,601 1,698
Minority Interest................................................. (9,679) (9,054) (9,559)
---------- ---------- ----------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle ........................................... 851,304 710,503 623,660
Income Taxes...................................................... 19,726 16,631 15,283
---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting Principle 831,578 693,872 608,377
Cumulative effect adjustment from change in accounting for asset
retirement obligations.......................................... - 3,465 -
---------- ---------- ----------
Net Income........................................................ $ 831,578 $ 697,337 $ 608,377
========== ========== ==========
Calculation of Limited Partners' Interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting $ 831,578 $ 693,872 $ 608,377
Principle.........................................................
Less: General Partner's interest................................ (395,092) (326,489) (270,816)
---------- ---------- ----------
Limited Partners' interest...................................... 436,486 367,383 337,561
Add: Limited Partners' interest in Change in Accounting Principle - 3,430 -
---------- ---------- ----------
Limited Partners' interest in Net Income........................ $ 436,486 $ 370,813 $ 337,561
========== ========== ==========
Basic and Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 2.22 $ 1.98 $ 1.96
Principle.........................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations........................................ - 0.02 -
---------- ---------- ----------
Net Income...................................................... $ 2.22 $ 2.00 $ 1.96
========== =========== ==========
Weighted average number of units used in computation of Limited
Partners' Net Income per Unit:
Basic............................................................. 196,956 185,384 172,017
========== ========== ==========
Diluted........................................................... 197,038 185,494 172,186
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
103
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
2004 2003 2002
---------- ---------- -------
(In thousands)
<S> <C> <C> <C>
Net Income.................................................. $ 831,578 $ 697,337 $ 608,377
Foreign currency translation adjustments.................... 375 -- --
Change in fair value of derivatives
used for hedging purposes................................ (494,212) (192,618) (116,560)
Reclassification of change in fair value of derivatives to net
income................................................... 192,304 82,065 7,477
--------- --------- ---------
Comprehensive Income........................................ $ 530,045 $ 586,784 $ 499,294
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
104
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
2004 2003
----------- --------
ASSETS (Dollars in thousands)
Current Assets
<S> <C> <C>
Cash and cash equivalents................................ $ - $ 23,329
Accounts, notes and interest receivable, net
Trade................................................. 739,798 563,012
Related parties....................................... 12,482 27,587
Inventories
Products.............................................. 17,868 7,214
Materials and supplies................................ 11,345 10,783
Gas imbalances
Trade................................................. 24,653 36,449
Related parties....................................... 980 9,084
Gas in underground storage............................... - 8,160
Other current assets..................................... 46,045 19,904
----------- ----------
853,171 705,522
Property, Plant and Equipment, net......................... 8,168,680 7,091,558
Investments................................................ 413,255 404,345
Notes receivable
Trade.................................................... 1,944 2,422
Related parties.......................................... 111,225 -
Goodwill................................................... 732,838 729,510
Other intangibles, net..................................... 15,284 13,202
Deferred charges and other assets.......................... 256,545 192,623
----------- ----------
Total Assets............................................... $10,552,942 $9,139,182
=========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts.................................. $ 29,866 $ -
Trade................................................. 685,034 477,783
Related parties....................................... 16,650 -
Current portion of long-term debt........................ - 2,248
Accrued interest......................................... 56,930 52,356
Accrued taxes............................................ 26,435 20,857
Deferred revenues........................................ 7,825 10,752
Gas imbalances........................................... 32,452 49,912
Accrued other current liabilities........................ 325,663 190,471
----------- ----------
1,180,855 804,379
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................................... 4,722,410 4,316,678
Market value of interest rate swaps................... 130,153 121,464
----------- ----------
4,852,563 4,438,142
Deferred revenues........................................ 14,680 20,975
Deferred income taxes.................................... 56,487 38,106
Asset retirement obligations............................. 37,464 34,898
Other long-term liabilities and deferred credits......... 468,727 251,691
----------- ----------
5,429,921 4,783,812
Commitments and Contingencies (Notes 13 and 16)
Minority Interest.......................................... 45,646 40,064
----------- ----------
Partners' Capital
Common Units (147,537,908 and 134,729,258 units issued and
outstanding as of December 31, 2004 and 2003,
respectively)......................................... 2,438,011 1,946,116
Class B Units (5,313,400 and 5,313,400 units issued and
outstanding as of December 31, 2004 and 2003,
respectively)......................................... 117,414 120,582
i-Units (54,157,641 and 48,996,465 units issued and
outstanding as of December 31, 2004 and 2003,
respectively)........................................ 1,694,971 1,515,659
General Partner.......................................... 103,467 84,380
Accumulated other comprehensive loss..................... (457,343) (155,810)
----------- ----------
3,896,520 3,510,927
Total Liabilities and Partners' Capital.................... $10,552,942 $9,139,182
=========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
2004 2003 2002
----------- ----------- -----------
(In thousands)
Cash Flows From Operating Activities
<S> <C> <C> <C>
Net income................................................ $ 831,578 $ 697,337 $ 608,377
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect adj. from change in accounting
for asset retirement obligations...................... -- (3,465) --
Depreciation, depletion and amortization................ 288,626 219,032 172,041
Amortization of excess cost of equity investments....... 5,575 5,575 5,575
Earnings from equity investments........................ (83,190) (92,199) (89,258)
Distributions from equity investments..................... 65,248 83,000 77,735
Changes in components of working capital:
Accounts receivable..................................... (172,393) (180,632) (177,240)
Other current assets.................................... 26,175 (1,858) (7,583)
Inventories............................................. (7,353) (2,945) (1,713)
Accounts payable........................................ 222,377 92,702 288,712
Accrued liabilities..................................... (18,482) 9,740 26,132
Accrued taxes........................................... 3,444 (4,904) 2,379
FERC rate reparations and refunds......................... -- (44,944) --
Other, net................................................ (6,497) (7,923) (35,462)
----------- ----------- -----------
Net Cash Provided by Operating Activities................... 1,155,108 768,516 869,695
----------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets.................................... (478,830) (349,867) (908,511)
Additions to property, plant and equip.
for expansion and maintenance projects................ (747,262) (576,979) (542,235)
Sale of investments, property, plant and equipment,
net of removal costs..................................... 1,069 2,090 13,912
Acquisitions of investments............................... (1,098) (10,000) (1,785)
Contributions to equity investments....................... (7,010) (14,052) (10,841)
Natural gas stored underground and
natural gas liquids line-fill............................ (19,189) 5,459 (884)
Other..................................................... 1,810 288 (536)
----------- ----------- -----------
Net Cash Used in Investing Activities....................... (1,250,510) (943,061) (1,450,880)
----------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt.......................................... 6,016,670 4,674,605 3,803,414
Payment of debt........................................... (5,657,566) (4,014,296) (2,985,322)
Loans to related party.................................... (96,271) -- --
Debt issue costs.......................................... (5,843) (5,204) (17,006)
Increase in cash book overdrafts.......................... 29,866 -- --
Proceeds from issuance of common units.................... 506,520 175,567 1,586
Proceeds from issuance of i-units......................... 67,528 -- 331,159
Contributions from General Partner........................ 7,956 4,181 3,353
Distributions to partners:
Common units............................................ (389,912) (340,927) (306,590)
Class B units........................................... (14,931) (13,682) (12,540)
General Partner......................................... (376,005) (314,244) (253,344)
Minority interest....................................... (10,117) (10,445) (9,668)
Other, net................................................ (5,822) 1,231 4,429
------------ ----------- -----------
Net Cash Provided by Financing Activities................... 72,073 156,786 559,471
----------- ----------- -----------
Decrease in Cash and Cash Equivalents....................... (23,329) (17,759) (21,714)
Cash and Cash Equivalents, beginning of period.............. 23,329 41,088 62,802
----------- ----------- -----------
Cash and Cash Equivalents, end of period.................... $ -- $ 23,329 $ 41,088
=========== =========== ===========
Noncash Investing and Financing Activities:
Assets acquired by the issuance of units.................. $ 64,050 $ 2,000 $ --
Assets acquired by the assumption of liabilities.......... 81,403 36,187 213,861
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for
Interest (net of capitalized interest).................... 193,247 183,908 161,840
Income taxes.............................................. (752) (261) 1,464
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
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<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
2004 2003 2002
------------------------ ------------------------- ------------------------
Units Amount Units Amount Units Amount
----------- ----------- ------------ ----------- ----------- -----------
(Dollars in thousands)
Common Units:
Beginning Balance..................... 134,729,258 $ 1,946,116 129,943,218 $ 1,844,553 129,855,018 $ 1,894,677
Net income............................ -- 311,237 -- 265,423 -- 254,934
Units issued as consideration in the
acquisition of assets............... 1,400,000 64,050 51,490 2,000 -- --
Units issued for cash................. 11,408,650 506,520 4,734,550 175,067 88,200 1,532
Distributions......................... -- (389,912) -- (340,927) -- (306,590)
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance........................ 147,537,908 2,438,011 134,729,258 1,946,116 129,943,218 1,844,553
Class B Units:
Beginning Balance..................... 5,313,400 120,582 5,313,400 123,635 5,313,400 125,750
Net income............................ -- 11,763 -- 10,629 -- 10,427
Units issued for cash................. -- -- -- -- -- (2)
Distributions......................... -- (14,931) -- (13,682) -- (12,540)
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance........................ 5,313,400 117,414 5,313,400 120,582 5,313,400 123,635
i-Units:
Beginning Balance..................... 48,996,465 1,515,659 45,654,048 1,420,898 30,636,363 1,020,153
Net income............................ -- 113,486 -- 94,761 -- 72,200
Units issued for cash................. 1,660,664 65,826 -- -- 12,478,900 328,545
Distributions......................... 3,500,512 -- 3,342,417 -- 2,538,785 --
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance........................ 54,157,641 1,694,971 48,996,465 1,515,659 45,654,048 1,420,898
General Partner:
Beginning Balance..................... -- 84,380 -- 72,100 -- 54,628
Net income............................ -- 395,092 -- 326,524 -- 270,816
Units issued for cash................. -- -- -- -- -- --
Distributions......................... -- (376,005) -- (314,244) -- (253,344)
------------ ------------ ----------- ----------- ----------- ------------
Ending Balance........................ -- 103,467 -- 84,380 -- 72,100
Accum. other comprehensive income (loss):
Beginning Balance..................... -- (155,810) -- (45,257) -- 63,826
Foreign currency translation adjustments -- 375 -- -- -- --
Change in fair value of derivatives
used for hedging purposes........... -- (494,212) -- (192,618) -- (116,560)
Reclassification of change in fair
value of derivatives to net income.. -- 192,304 -- 82,065 -- 7,477
------------ ----------- ------------ ----------- ------------ ------------
Ending Balance........................ -- (457,343) -- (155,810) -- (45,257)
Total Partners' Capital................. 207,008,949 $ 3,896,520 189,039,123 $ 3,510,927 180,910,666 $ 3,415,929
=========== =========== ============ ============ =========== ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
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<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
General
Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership
formed in August 1992. Unless the context requires otherwise, references to
"we," "us," "our" or the "Partnership" are intended to mean Kinder Morgan Energy
Partners, L.P. and its consolidated subsidiaries.
We own and manage a diversified portfolio of energy transportation and
storage assets. We provide services to our customers and create value for our
unitholders primarily through the following activities:
o transporting, storing and processing refined petroleum products;
o transporting, storing and selling natural gas;
o producing, transporting and selling carbon dioxide, commonly called
CO2, for use in, and selling crude oil produced from, enhanced oil
recovery operations; and
o transloading, storing and delivering a wide variety of bulk, petroleum
and petrochemical products at terminal facilities located across the
United States.
We focus on providing fee-based services to customers, generally avoiding
near-term commodity price risks and taking advantage of the tax benefits of a
limited partnership structure. We trade on the New York Stock Exchange under the
symbol "KMP" and presently conduct our business through four reportable business
segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2; and
o Terminals.
For more information on our reportable business segments, see Note 15.
Kinder Morgan, Inc.
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,
Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. KMI trades on
the New York Stock Exchange under the symbol "KMI" and is one of the largest
energy transportation and storage companies in the United States, operating,
either for itself or on our behalf, more than 35,000 miles of natural gas and
products pipelines and approximately 135 terminals. At December 31, 2004, KMI
and its consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 18.5% interest in us.
Kinder Morgan Management, LLC
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. It is referred to as "KMR" in this report. Our
general partner owns all of KMR's voting securities and, pursuant to a
delegation of control agreement, our general partner has delegated to KMR, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control our business and
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affairs, except that KMR cannot take certain specified actions without the
approval of our general partner. Under the delegation of control agreement, KMR
manages and controls our business and affairs and the business and affairs of
our operating limited partnerships and their subsidiaries. Furthermore, in
accordance with its limited liability company agreement, KMR's activities are
limited to being a limited partner in, and managing and controlling the business
and affairs of us, our operating limited partnerships and their subsidiaries. As
of December 31, 2004, KMR owned approximately 26.2% of our outstanding limited
partner units (which are in the form of i-units that are issued only to KMR).
2. Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior years have been reclassified to conform to the current
presentation.
Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated by management, requiring us to make certain assumptions with
respect to values or conditions which cannot be known with certainty at the time
the financial statements are prepared. These estimates and assumptions affect
the amounts we report for assets and liabilities and our disclosure of
contingent assets and liabilities at the date of the financial statements.
Therefore, the reported amounts of our assets and liabilities and
associated disclosures with respect to contingent assets and obligations are
necessarily affected by these estimates. We evaluate these estimates on an
ongoing basis, utilizing historical experience, consultation with experts and
other methods we consider reasonable in the particular circumstances.
Nevertheless, actual results may differ significantly from our estimates. Any
effects on our business, financial position or results of operations resulting
from revisions to these estimates are recorded in the period in which the facts
that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others.
Cash Equivalents
We define cash equivalents as all highly liquid short-term investments with
original maturities of three months or less.
Accounts Receivables
Our policy for determining an appropriate allowance for doubtful accounts
varies according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed circumstances
and customer-specific information. When specific receivables are determined to
be uncollectible, the reserve and receivable are relieved. The following tables
show the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2004, 2003 and 2002.
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<PAGE>
Valuation and Qualifying Accounts
(in thousands)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Balance at Additions Additions Balance at
beginning of charged to costs charged to other end of
Allowance for Doubtful Accounts Period and expenses accounts(1) Deductions(2) period
-------------------------------- ------------ ---------------- ----------------- ----------------- -----------
Year ended December 31, 2004.... $8,783 $1,460 $ 431 $(2,052) $8,622
Year ended December 31, 2003.... $8,092 $1,448 $ - $ (757) $8,783
Year ended December 31, 2002.... $7,556 $ 822 $ 4 $ (290) $8,092
</TABLE>
__________
(1) Amount for 2004 represents the allowance recognized when we acquired Kinder
Morgan River Terminals LLC and Consolidated Subsidiaries ($393) and
TransColorado Gas Transmission Company ($38). Amount for 2002 represents
the allowance recognized when we acquired IC Terminal Holdings Company and
Consolidated Subsidiaries.
(2) Deductions represent the write-off of receivables.
In addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $5.1 million as of December 31, 2004 and $8.2
million as of December 31, 2003.
Inventories
Our inventories of products consist of natural gas liquids, refined
petroleum products, natural gas, carbon dioxide and coal. We report these assets
at the lower of weighted-average cost or market. We report materials and
supplies at the lower of cost or market.
Property, Plant and Equipment
We report property, plant and equipment at its acquisition cost. We expense
costs for maintenance and repairs in the period incurred. The cost of property,
plant and equipment sold or retired and the related depreciation are removed
from our balance sheet in the period of sale or disposition. We charge the
original cost of property sold or retired to accumulated depreciation and
amortization, net of salvage and cost of removal. We do not include retirement
gain or loss in income except in the case of significant retirements or sales.
Gains and losses on minor system sales, excluding land, are recorded to the
appropriate accumulated depreciation reserve. Gains and losses for operating
systems sales and land sales are booked to income or expense accounts in
accordance with regulatory accounting guidelines.
We compute depreciation using the straight-line method based on estimated
economic lives. Generally, we apply composite depreciation rates to functional
groups of property having similar economic characteristics. The rates range from
2.0% to 12.5%, excluding certain short-lived assets such as vehicles. In
practice, the composite life may not be determined with a high degree of
precision, and hence the composite life may not reflect the weighted average of
the expected useful lives of the asset's principal components.
Our oil and gas producing activities are accounted for under the successful
efforts method of accounting. Under this method costs that are incurred to
acquire leasehold and subsequent development costs are capitalized. Costs that
are associated with the drilling of successful exploration wells are capitalized
if proved reserves are found. Costs associated with the drilling of exploratory
wells that do not find proved reserves, geological and geophysical costs, and
costs of certain non-producing leasehold costs are expensed as incurred. The
capitalized costs of our producing oil and gas properties are depreciated and
depleted by the units-of-production method. Other miscellaneous property, plant
and equipment are depreciated over the estimated useful lives of the asset.
A gain on the sale of property, plant and equipment used in our oil and gas
producing activities is calculated as the difference between the cost of the
asset disposed of, net of depreciation, and the sales proceeds received. A gain
on an asset disposal is recognized in income in the period that the sale is
closed. A loss on the sale of property,
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plant and equipment is calculated as the difference between the cost of the
asset disposed of, net of depreciation, and the sales proceeds received or the
maket value if the asset is being held for sale. A loss is recognized when the
asset is sold or when the net cost of an asset held for sale is greater than the
market value of the asset.
In addition, we engage in enhanced recovery techniques in which carbon
dioxide is injected into certain producing oil reservoirs. In some cases, the
acquisition cost of the carbon dioxide associated with enhanced recovery is
capitalized as part of our development costs when it is injected. The
acquisition cost associated with pressure maintenance operations for reservoir
management is expensed when it is injected. When carbon dioxide is recovered in
conjunction with oil production, it is extracted and re-injected, and all of the
associated costs are expensed as incurred. Proved developed reserves are used in
computing units of production rates for drilling and development costs, and
total proved reserves are used for depletion of leasehold costs. The
units-of-production rate is determined by field.
We review for the impairment of long-lived assets whenever events or
changes in circumstances indicate that our carrying amount of an asset may not
be recoverable. We would recognize an impairment loss when estimated future cash
flows expected to result from our use of the asset and its eventual disposition
is less than its carrying amount.
We evaluate our oil and gas producing properties for impairment of value on a
field-by-field basis or, in certain instances, by logical grouping of assets if
there is significant shared infrastructure, using undiscounted future cash flows
based on total proved and risk-adjusted probable and possible reserves. Oil and
gas producing properties deemed to be impaired are written down to their fair
value, as determined by discounted future cash flows based on total proved and
risk-adjusted probable and possible reserves or, if available, comparable market
values. Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of impairment.
On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we
now evaluate the impairment of our long-lived assets in accordance with this
Statement. This Statement retains the requirements of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," however, this Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
the cost to sell. Furthermore, the scope of discontinued operations is expanded
to include all components of an entity with operations of the entity in a
disposal transaction. The adoption of SFAS No. 144 has not had an impact on our
business, financial position or results of operations.
Equity Method of Accounting
We account for investments greater than 20% in affiliates, which we do not
control, by the equity method of accounting. Under this method, an investment is
carried at our acquisition cost, plus our equity in undistributed earnings or
losses since acquisition, and less distributions received.
Excess of Cost Over Fair Value
Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations"
and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141
supercedes Accounting Principles Board Opinion No. 16 and requires that all
transactions fitting the description of a business combination be accounted for
using the purchase method and prohibits the use of the pooling of interests for
all business combinations initiated after June 30, 2001. The Statement also
modifies the accounting for the excess of cost over the fair value of net assets
acquired as well as intangible assets acquired in a business combination. The
provisions of this Statement apply to all business combinations initiated after
June 30, 2001, and all business combinations accounted for by the purchase
method that are completed after July 1, 2001. In addition, this Statement
requires disclosure of the primary reasons for a business combination and the
allocation of the purchase price paid to the assets acquired and liabilities
assumed by major balance sheet caption.
SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and
requires that goodwill no longer be amortized, but instead should be tested, at
least on an annual basis, for impairment. A benchmark assessment of potential
impairment was required to be completed within six months of adopting SFAS No.
142. After the first six months, goodwill must be tested for impairment annually
or as changes in circumstances require. Other intangible assets are to be
amortized over their useful life and reviewed for impairment in accordance with
the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." An intangible asset with an indefinite useful life can no
longer be amortized until its useful life becomes determinable. In addition,
this Statement requires disclosure of information about goodwill and other
intangible assets in the years subsequent to their acquisition that was not
previously required. Required disclosures include information about the changes
in the carrying amount of goodwill from period to period and the carrying amount
of intangible assets by major intangible asset class.
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These accounting pronouncements required that, beginning with their
implementation, we prospectively cease amortization of all intangible assets
having indefinite useful economic lives. Such assets, including goodwill, are
not to be amortized until their lives are determined to be finite. A recognized
intangible asset with an indefinite useful life should be tested for impairment
annually or on an interim basis if events or circumstances indicate that the
fair value of the asset has decreased below its carrying value. We completed the
initial transition impairment test in June 2002 and determined that our goodwill
was not impaired as of January 1, 2002. We have selected an impairment
measurement test date of January 1 of each year and we have determined that our
goodwill was not impaired as of January 1, 2005.
Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $732.8 million as of December 31, 2004
and $729.5 million as of December 31, 2003. Such amounts are reported as
"Goodwill" on our accompanying consolidated balance sheets. Our total
unamortized excess cost over underlying fair value of net assets accounted for
under the equity method was approximately $150.3 million as of both December 31,
2004, and December 31, 2003. Pursuant to SFAS No. 142, this amount, referred to
as equity method goodwill, should continue to be recognized in accordance with
Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock." Accordingly, we included this amount within
"Investments" on our accompanying consolidated balance sheets. In addition,
approximately $184.2 million and $189.7 million at December 31 2004 and 2003,
respectively, representing the excess of the fair market value of property,
plant and equipment over its book value at the date of acquisition was included
within "Investments" on our accompanying consolidated balance sheets and was
being amortized over a weighted average life of approximately 33.6 years.
In addition to our annual impairment test of goodwill, we periodically
reevaluate the amount at which we carry the excess of cost over fair value of
net assets of businesses we acquired, as well as the amortization period for
such assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. As of December 31, 2004, we believed no such impairment had occurred
and no reduction in estimated useful lives was warranted.
For more information on our acquisitions, see Note 3. For more information
on our investments, see Note 7.
Revenue Recognition
We recognize revenues for our pipeline operations based on delivery of
actual volume transported or minimum obligations under take-or-pay contracts. We
recognize bulk terminal transfer service revenues based on volumes loaded. We
recognize liquids terminal tank rental revenue ratably over the contract period.
We recognize liquids terminal through-put revenue based on volumes received or
volumes delivered depending on the customer contract. Liquids terminal minimum
take-or-pay revenue is recognized at the end of the contract year or contract
term depending on the terms of the contract. We recognize transmix processing
revenues based on volumes processed or sold, and if applicable, when title has
passed. We recognize energy-related product sales revenues based on delivered
quantities of product.
Revenues from the sale of oil and natural gas liquids production are
recorded using the entitlement method. Under the entitlement method, revenue is
recorded when title passes based on our net interest. We record our entitled
share of revenues based on entitled volumes and contracted sales prices.
Revenues from the sale of natural gas production are recognized when the natural
gas is sold. Since there is a ready market for oil and gas production, we sell
the majority of our products soon after production at various locations, at
which time title and risk of loss pass to the buyer. As a result, we maintain a
minimum amount of product inventory in storage and the differences between
actual production and sales is not significant.
Capitalized Interest
We capitalize interest expense during the construction or upgrade of
qualifying assets. Interest expense capitalized in 2004, 2003 and 2002 was $6.4
million, $5.3 million and $5.8 million, respectively.
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Unit-Based Compensation
SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure,"
encourages, but does not require, entities to adopt the fair value method of
accounting for stock or unit-based compensation plans. As allowed under SFAS No.
123, we apply APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations in accounting for common unit options granted under
our common unit option plan. Accordingly, compensation expense is not recognized
for common unit options unless the options are granted at an exercise price
lower than the market price on the grant date. No compensation expense has been
recorded since the options were granted at exercise prices equal to the market
prices at the date of grant. Pro forma information regarding changes in net
income and per unit data, if the accounting prescribed by SFAS No. 123 had been
applied, is not material. For more information on unit-based compensation, see
Note 13.
Environmental Matters
We expense or capitalize, as appropriate, environmental expenditures that
relate to current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a net
present value, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We recognize receivables for anticipated associated insurance recoveries when
such recoveries are deemed to be probable.
We utilize both internal staff and external experts to assist us in
identifying environmental issues and in estimating the costs and timing of
remediation efforts. Often, as the remediation evaluation and effort progresses,
additional information is obtained, requiring revisions to estimated costs.
These revisions are reflected in our income in the period in which they are
reasonably determinable.
We routinely conduct reviews of potential environmental issues and claims
that could impact our assets or operations. In December 2004, we recognized a
$0.2 million increase in environmental expenses and an associated $0.1 million
increase in deferred income tax expense resulting from changes to previous
estimates. The adjustment included an $18.9 million increase in our estimated
environmental receivables and reimbursables and a $19.1 million increase in our
overall accrued environmental and related claim liabilities. We included the
additional $0.2 million environmental expense within "Other, net" in our
accompanying consolidated statement of income for 2004. The $0.3 million expense
item, including taxes, is the net impact of a $30.6 million increase in expense
in our Products Pipelines business segment, a $7.6 million decrease in expense
in our Natural Gas Pipelines segment, a $4.1 million decrease in expense in our
CO2 segment, and an $18.6 million decrease in expense in our Terminals business
segment.
In December 2002, we recognized a $0.3 million reduction in environmental
expense and in our overall accrued environmental liability, and we included this
amount within "Other, net" in our accompanying consolidated statement of income
for 2002. The $0.3 million reduction in environmental expense resulted from a
$15.7 million loss in our Products Pipelines business segment and a $16.0
million gain in our Terminals business segment. For more information on our
environmental disclosures, see Note 16.
Legal
We are subject to litigation and regulatory proceedings as the result of
our business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to reviseour
estimates, our earnings will be affected. We expense legal costs as incurred and
all recorded legal liabilities are revised as better information becomes
available. For more information on our legal
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disclosures, see Note 16.
Pension
We are required to make assumptions and estimates regarding the accuracy of
our pension investment returns. Specifically, these include:
o our investment return assumptions;
o the significant estimates on which those assumptions are based; and
o the potential impact that changes in those assumptions could have on
our reported results of operations and cash flows.
We consider our overall pension liability exposure to be minimal in
relation to the value of our total consolidated assets and net income. However,
in accordance with SFAS No. 87, "Employers' Accounting for Pensions," our net
periodic pension cost includes the return on pension plan assets, including both
realized and unrealized changes in the fair market value of pension plan assets.
A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10.
Gas Imbalances and Gas Purchase Contracts
We value gas imbalances due to or due from interconnecting pipelines at the
lower of cost or market. Gas imbalances represent the difference between
customer nominations and actual gas receipts from and gas deliveries to our
interconnecting pipelines under various operational balancing agreements.
Natural gas imbalances are either settled in cash or made up in-kind subject to
the pipelines' various tariff provisions.
Minority Interest
As of December 31, 2004, minority interest consisted of the following:
o the 1.0101% general partner interest in each of our five operating
partnerships;
o the 0.5% special limited partner interest in SFPP, L.P.;
o the 50% interest in Globalplex Partners, a Louisiana joint venture
owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;
o the 33 1/3% interest in International Marine Terminals Partnership, a
Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan
Operating L.P. "C";
o the approximate 31% interest in the Pecos Carbon Dioxide Company, a
Texas general partnership owned approximately 69% and controlled by
Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries;
o the 1% interest in River Terminals Properties, L.P., a Tennessee
partnership owned 99% and controlled by Kinder Morgan River Terminals
LLC; and
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o the 25% interest in Guilford County Terminal Company, LLC, a limited
liability company owned 75% and controlled by Kinder Morgan Southeast
Terminals LLC.
Income Taxes
We are not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or net loss we report in our consolidated
statement of income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have access
to information about each partner's tax attributes in us.
Some of our corporate subsidiaries and corporations in which we have an
equity investment do pay federal and state income taxes. Deferred income tax
assets and liabilities for certain operations conducted through corporations are
recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. Changes in tax legislation are included in
the relevant computations in the period in which such changes are effective.
Deferred tax assets are reduced by a valuation allowance for the amount of any
tax benefit not expected to be realized.
Foreign Currency Translation
In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly
Global Materials Services LLC. Included in the acquisition was Arrow Terminals,
B.V., a wholly-owned subsidiary of Kinder Morgan River Terminals LLC that
conducts bulk terminal operations in The Netherlands. We translate the assets
and liabilities of Arrow Terminals, B.V. to U.S. dollars at year-end exchange
rates. Income and expense items are translated at weighted-average rates of
exchange prevailing during the year and stockholders' equity accounts are
translated by using historical exchange rates. Translation adjustments result
from translating all assets and liabilities at current year-end rates, while
stockholders' equity is translated by using historical and weighted-average
rates. The cumulative translation adjustments balance is reported as a component
of accumulated other comprehensive income within Partners' Capital on our
accompanying balance sheet. Due to the limited size of our foreign operations,
we do not believe these foreign currency translations are material to our
financial position.
Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income," requires that enterprises report a total for
comprehensive income. For the year ended December 31, 2004, the difference
between our net income and our comprehensive income resulted from unrealized
gains or losses on derivatives utilized for hedging purposes and from foreign
currency translation adjustments. For each of the years ended December 31, 2003
and 2002, the only difference between our net income and our comprehensive
income was the unrealized gain or loss on derivatives utilized for hedging
purposes. For more information on our risk management activities, see Note 14.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing Limited
Partners' interest in Net Income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
Asset Retirement Obligations
As of January 1, 2003, we account for asset retirement obligations pursuant
to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more
information on our asset retirement obligations, see Note 4.
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Risk Management Activities
We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our debt obligations.
Our derivatives are accounted for under SFAS No. 133, as amended by SFAS
No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No.133" and No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities."
SFAS No. 133 established accounting and reporting standards requiring that every
derivative financial instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either an asset
or liability measured at its fair value. SFAS No. 133 requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.
Furthermore, if the derivative transaction qualifies for and is designated
as a normal purchase and sale, it is exempted from the fair value accounting
requirements of SFAS No. 133 and is accounted for using traditional accrual
accounting. Our derivatives that hedge our commodity price risks involve our
normal business activities, which include the sale of natural gas, natural gas
liquids, oil and carbon dioxide, and these derivatives have been designated as
cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives
that hedge exposure to variable cash flows of forecasted transactions as cash
flow hedges and the effective portion of the derivative's gain or loss is
initially reported as a component of other comprehensive income (outside
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
reported in earnings immediately. See Note 14 for more information on our risk
management activities.
3. Acquisitions and Joint Ventures
During 2002, 2003 and 2004, we completed or made adjustments for the
following significant acquisitions. Each of the acquisitions was accounted for
under the purchase method and the assets acquired and liabilities assumed were
recorded at their estimated fair market values as of the acquisition date. The
preliminary allocation of assets and liabilities may be adjusted to reflect the
final determined amounts during a short period of time following the
acquisition. The results of operations from these acquisitions are included in
our consolidated financial statements from the acquisition date.
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<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Allocation of Purchase Price
-------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest
----- -------------------------------------------------- ------------- --------- ----------- --------- --------- ----------
(1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.1 $ 0.9 $ 13.2 $- $- $-
(2) 1/02 66 2/3% Interest in Intl. MarineTerminals. 40.5 6.6 31.8 0.1 - 2.0
(3) 1/02 Kinder Morgan Tejas....................... 878.5 56.5 674.1 - 147.9 -
(4) 5/02 Milwaukee Bagging Operations.............. 8.5 0.1 3.1 - 5.3 -
(5) 5/02 Trailblazer Pipeline Company.............. 80.1 - 41.7 - 15.0 23.4
(6) 9/02 Owensboro Gateway Terminal................ 7.7 0.0 4.3 0.1 3.3 -
(7) 9/02 IC Terminal Holdings Company.............. 17.7 0.1 14.3 3.3 - -
(8) 1/03 Bulk Terminals from M.J. Rudolph.......... 31.3 0.1 18.2 0.1 12.9 -
(9) 6/03 MKM Partners, L.P......................... 25.2 - 25.2 - - -
(10) 8/03 Interest in Red Cedar Gathering Company... 10.0 - - 10.0 - -
(11) 10/03 Shell Products Terminals.................. 20.0 - 20.0 - - -
(12) 11/03 Yates Field Unit and Carbon Dioxide Assets 259.9 3.6 256.6 - - (0.3)
(13) 11/03 Interest in MidTex Gas Storage Co., LLP... 17.5 - 11.9 - - 5.6
(14) 12/03 ConocoPhillips Products Terminals......... 15.3 - 14.3 1.0 - -
(15) 12/03 Tampa, Florida Bulk Terminals............. 29.1 - 29.1 - - -
(16) 3/04 ExxonMobil Products Terminals............. 50.9 - 50.9 - - -
(17) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 100.2 - - -
(18) 10/04 Interest in Cochin Pipeline System........ 10.9 - 10.9 - - -
(19) 10/04 Kinder Morgan River Terminals LLC......... 89.6 9.9 70.2 3.1 6.4 -
(20) 11/04 Charter Products Terminals................ 75.2 3.7 71.8 0.8 - (1.1)
(21) 11/04 TransColorado Gas Transmission Company.... 284.5 2.0 280.6 1.9 - -
(22) 12/04 Kinder Morgan Fairless Hills Terminal..... $ 7.5 $ - $ 6.2 $1.3 $- $-
</TABLE>
(1) Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of
Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for
an aggregate consideration of $14.1 million, consisting of approximately $10.8
million in cash and the assumption of approximately $3.3 million of liabilities,
including long-term debt of $0.4 million. Kinder Morgan Materials Services LLC
currently operates approximately 60 transload facilities in 20 states. The
facilities handle dry-bulk products, including aggregates, plastics and liquid
chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded our
growing terminal operations and is part of our Terminals business segment.
(2) 66 2/3% Interest in International Marine Terminals
Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals Partnership, referred to in this report as IMT, from Marine
Terminals Incorporated. Effective February 1, 2002, we acquired an additional 33
1/3% interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase
price was approximately $40.5 million, including the assumption of $40 million
of long-term debt. IMT is a partnership that operates a bulk terminal site in
Port Sulphur, Louisiana. This terminal is a multi-purpose import and export
facility, which handles approximately 10 million tons annually of bulk products
including coal, petroleum coke, iron ore and barite. The acquisition complements
our existing bulk terminal assets. IMT is part of our Terminals business
segment.
(3) Kinder Morgan Tejas
Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for
an aggregate consideration of approximately $878.5 million, consisting of $727.1
million in cash and the assumption of $151.4 million of liabilities. Tejas Gas,
LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system
that extends from south Texas along the Mexico border and the Texas Gulf Coast
to near the Louisiana border and north from near Houston to east Texas. The
acquisition expanded our natural gas operations within the State of Texas. The
acquired assets are referred to as Kinder Morgan Tejas in this report and are
included in our Natural Gas Pipelines business segment. The combination of these
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systems is part of our Texas intrastate natural gas pipeline group. Our
allocation to assets acquired and liabilities assumed was based on an appraisal
of fair market values. The $147.9 million of goodwill was assigned to our
Natural Gas Pipelines business segment and the entire amount is expected to be
deductible for tax purposes.
(4) Milwaukee Bagging Operations
Effective May 1, 2002, we purchased a bagging operation facility adjacent
to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee bulk terminal, which is capable of
handling up to 150,000 tons per year of fertilizer and salt for de-icing and
livestock purposes. The Milwaukee bagging operations are included in our
Terminals business segment. The $5.3 million of goodwill was assigned to our
Terminals business segment and the entire amount is expected to be deductible
for tax purposes.
(5) Trailblazer Pipeline Company
On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company that we did not already own from Enron Trailblazer
Pipeline Company for an aggregate consideration of $80.1 million. We now own
100% of Trailblazer Pipeline Company. In May 2002, we paid $68 million to an
affiliate of Enron Corp., and during the first quarter of 2002, we paid $12.1
million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in
exchange for CIG's relinquishment of its rights to become a 7% to 8% equity
owner in Trailblazer Pipeline Company in mid-2002. Trailblazer Pipeline Company
is an Illinois partnership that owns and operates a 436-mile natural gas
pipeline system that traverses from Colorado through southeastern Wyoming to
Beatrice, Nebraska. Trailblazer Pipeline Company has a current certificated
capacity of 846 million cubic feet per day of natural gas. The $15.0 million of
goodwill was assigned to our Natural Gas Pipelines business segment and the
entire amount is expected to be deductible for tax purposes.
(6) Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. In September 2002,
we paid approximately $7.2 million and established a $0.5 million purchase price
retention liability to be paid at the later of: (i) one year following the
acquisition, or (ii) the day we received consent to the assignment of a contract
between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5
million liability in September 2003. The facility is one of the nation's largest
storage and handling points for bulk aluminum. The terminal also handles a
variety of other bulk products, including petroleum coke, lime and de-icing
salt. The terminal is situated on a 92-acre site along the Ohio River, and the
purchase expanded our presence along the river, complementing our existing
facilities located near Cincinnati, Ohio and Moundsville, West Virginia. We
refer to the acquired terminal as our Owensboro Gateway Terminal and we include
its operations in our Terminals business segment. The $3.3 million of goodwill
was assigned to our Terminals business segment and the entire amount is expected
to be deductible for tax purposes.
(7) IC Terminal Holdings Company
Effective September 1, 2002, we acquired all of the shares of the capital
stock of IC Terminal Holdings Company from the Canadian National Railroad. Our
purchase price was $17.7 million, consisting of $17.4 million in cash and the
assumption of $0.3 million in liabilities. The total purchase price decreased
$0.2 million in the third quarter of 2003 primarily due to adjustments in the
amount of working capital items assumed on the acquisition date. The acquisition
included the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility has 400,000 barrels of liquids storage capacity and a related
pipeline network. The acquisition further expanded our terminal businesses along
the Mississippi River. The acquired terminal is referred to as the Kinder Morgan
St. Gabriel terminal, and we include its operations in our Terminals business
segment.
(8) Bulk Terminals from M.J. Rudolph
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk terminal facilities at
major ports along the East Coast and in the southeastern United States. The
acquisition also included the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid
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$29.9 million, and in the first quarter of 2003, we paid the remaining $1.4
million. The acquired operations serve various terminals located at the ports of
New York and Baltimore, along the Delaware River in Camden, New Jersey, and in
Tampa Bay, Florida. Combined, these facilities transload nearly four million
tons annually of products such as fertilizer, iron ore and salt. The acquisition
expanded our growing Terminals business segment and complements certain of our
existing terminal facilities. We include its operations in our Terminals
business segment, and in our final analysis, it was considered reasonable to
allocate a portion of our purchase price to goodwill given the substance of this
transaction, including expected benefits from integrating this acquisition with
our existing assets. The $12.9 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes.
(9) MKM Partners, L.P.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75%
ownership interest in the SACROC oil field unit for an aggregate consideration
of $25.2 million, consisting of $23.3 million in cash and the assumption of $1.9
million of liabilities. The SACROC unit is one of the largest and oldest oil
fields in the United States using carbon dioxide flooding technology. This
transaction increased our ownership interest in the SACROC unit to approximately
97%.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit, which we acquired
June 1, 2003 as described above, and a 49.9% interest in the Yates Field unit,
both of which are in the Permian Basin of West Texas. The MKM joint venture was
owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan CO2
Company, L.P. It was dissolved effective June 30, 2003, and the net assets were
distributed to partners in accordance with its partnership agreement.
(10) Interest in Red Cedar Gas Gathering Company
Effective August 1, 2003, we acquired reversionary interests in the Red
Cedar Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase
price was $10.0 million. The 4% reversionary interests were scheduled to take
effect September 1, 2004 and September 1, 2009. With the elimination of these
reversions, our ownership interest in Red Cedar will be maintained at 49% in the
future. The purchase price was allocated to our equity investment in Red Cedar,
included with our equity method goodwill.
(11) Shell Products Terminals
Effective October 1, 2003, we acquired five refined petroleum products
terminals in the western United States for approximately $20.0 million from
Shell Oil Products U.S. As of our acquisition date, we expected to invest an
additional $8.0 million in the facilities. The terminals are located in Colton
and Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada.
Combined, the terminals have 28 storage tanks with total capacity of
approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. As part of
the transaction, Shell has entered into a long-term contract to store products
in the terminals. The acquisition enhances our Pacific operations and
complements our existing West Coast Terminals. The acquired operations are
included as part of our Pacific operations and our Products Pipelines business
segment.
(12) Yates Field Unit and Carbon Dioxide Assets
Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price
was approximately $259.9 million, consisting of $230.2 million in cash and the
assumption of $29.7 million of liabilities. The assets acquired consisted of the
following:
o Marathon's approximate 42.5% interest in the Yates oil field unit. We
previously owned a 7.5% ownership interest in the Yates field unit and
we now operate the field;
o Marathon's 100% interest in the crude oil gathering system surrounding
the Yates field unit; and
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o Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon
Carbon Dioxide Transportation Company. Kinder Morgan Carbon Dioxide
Transportation Company owns a 65% ownership interest in the Pecos
Carbon Dioxide Pipeline Company, which owns a 25-mile carbon dioxide
pipeline. We previously owned a 4.27% ownership interest in the Pecos
Carbon Dioxide Pipeline Company and accounted for this investment
under the cost method of accounting. After the acquisition of our
additional 65% interest in Pecos, its financial results are included
in our consolidated results and we recognize the appropriate minority
interest.
Together, the acquisition of these assets complemented our existing carbon
dioxide assets in the Permian Basin, increased our working interest in the Yates
field to nearly 50% and allowed us to become the operator of the field. We
recorded a deferred tax liability of $0.8 million in August 2004 to properly
reflect the tax obligations of Kinder Morgan Carbon Dioxide Transportation
Company. The acquired operations are included as part of our CO2 business
segment.
(13) Interest in MidTex Gas Storage Company, LLP
Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP that we did not already
own from an affiliate of NiSource Inc. Our combined purchase price was
approximately $17.5 million, consisting of $15.8 million in cash and the
assumption of $1.7 million of debt. The debt represented a MidTex note payable
that was to be paid by the former partner. We now own 100% of MidTex Gas Storage
Company, LLP. MidTex Gas Storage Company, LLP is a Texas limited liability
partnership that owns two salt dome natural gas storage facilities located in
Matagorda County, Texas. MidTex's operations are included as part of our Natural
Gas Pipelines business segment.
(14) ConocoPhillips Products Terminals
Effective December 11, 2003, we acquired seven refined petroleum products
terminals located in the southeastern United States from ConocoPhillips Company
and Phillips Pipe Line Company. Our purchase price was approximately $15.3
million, consisting of approximately $14.1 million in cash and $1.2 million in
assumed liabilities. The terminals are located in Charlotte and Selma, North
Carolina; Augusta and Spartanburg, South Carolina; Albany and Doraville,
Georgia; and Birmingham, Alabama. We fully own and operate all of the terminals
except for the Doraville, Georgia facility, which is operated and owned 70% by
Citgo. As of our acquisition date, we expected to invest an additional $1.3
million in the facilities. Combined, the terminals have 35 storage tanks with
total capacity of approximately 1.15 million barrels for gasoline, diesel fuel
and jet fuel. As part of the transaction, ConocoPhillips entered into a
long-term contract to use the terminals. The contract consists of a five-year
terminaling agreement, an intangible asset which we valued at $1.0 million. The
acquisition broadened our refined petroleum products operations in the
southeastern United States as three of the terminals are connected to the
Plantation pipeline system, which is operated and owned 51% by us. The acquired
operations are included as part of our Products Pipelines business segment.
(15) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa,
Florida for an aggregate consideration of approximately $29.1 million,
consisting of $26.3 million in cash and $2.8 million in assumed liabilities. As
of our acquisition date, we expected to invest an additional $16.9 million in
the facilities. The principal facility purchased was a marine terminal acquired
from a subsidiary of The Mosaic Company, formerly IMC Global, Inc. We entered
into a long-term agreement with Mosaic pursuant to which Mosaic will be the
primary user of the facility, which we will operate and refer to as the Kinder
Morgan Tampaplex terminal. The terminal sits on a 114-acre site, and serves as a
storage and receipt point for imported ammonia, as well as an export location
for dry bulk products, including fertilizer and animal feed. We closed on the
Tampaplex portion of this transaction on December 23, 2003. The second facility
purchased was the former Nitram, Inc. bulk terminal, which we have converted to
an inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton, Florida import terminal. We closed on the Nitram portion of this
transaction on December 10, 2003. We recorded our final purchase price
adjustments in the third quarter of 2004. The adjustments included the removal
of a property tax liability in the amount of $0.6 million, which had been
established in December 2003 pending final determination of assumed tax
obligations. The
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acquired operations are included as part of our Terminals business segment and
complement our existing businesses in the Tampa area by generating additional
fee-based income.
(16) ExxonMobil Products Terminals
Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil Corporation. Our
purchase price was approximately $50.9 million, consisting of approximately
$48.2 million in cash and $2.7 million in assumed liabilities. The terminals are
located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro,
North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the
terminals have a total storage capacity of approximately 3.2 million barrels for
gasoline, diesel fuel and jet fuel. As part of the transaction, ExxonMobil
entered into a long-term contract to store products at the terminals. As of our
acquisition date, we expected to invest an additional $1.2 million in the
facilities. The acquisition enhanced our terminal operations in the Southeast
and complemented our December 2003 acquisition of seven products terminals from
ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations
are included as part of our Products Pipelines business segment.
(17) Kinder Morgan Wink Pipeline, L.P.
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.3 million, consisting of $89.9
million in cash and the assumption of approximately $10.4 million of
liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5
million outstanding debt balance. We renamed the limited partnership Kinder
Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its
results as part of our CO2 business segment. The acquisition included a 450-mile
crude oil pipeline system, consisting of four mainline sections, numerous
gathering systems and truck off-loading stations. The mainline sections, all in
Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of
the transaction, we entered into a long-term throughput agreement with Western
Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per
day refinery in El Paso, Texas. As of our acquisition date, we expected to
invest approximately $11.0 million over the next five years to upgrade the
assets. The acquisition allows us to better manage crude oil deliveries from our
oil field interests in West Texas.
(18) Interest in Cochin Pipeline
Effective October 1, 2004, we acquired an additional undivided 5% interest
in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation
for approximately $10.9 million. On November 3, 2000, we acquired from NOVA
Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System
for approximately $120.5 million. On June 20, 2001, we acquired an additional
2.3% ownership interest from Shell Canada Limited for approximately $8.1
million, and effective December 31, 2001, we purchased an additional 10%
ownership interest from NOVA Chemicals Corporation for approximately $29
million. We now own approximately 49.8% of the Cochin Pipeline System. A
subsidiary of BP owns the remaining interest and operates the pipeline. We
record our proportional share of joint venture revenues and expenses and cost of
joint venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment. Our allocation of the purchase price to
assets acquired is preliminary, pending any minor adjustments that may be
necessary under the purchase and sale agreement. We expect to make any final
adjustments by the end of the first quarter of 2005.
(19) Kinder Morgan River Terminals LLC
Effective October 6, 2004, we acquired Global Materials Services LLC and
its consolidated subsidiaries from Mid-South Terminal Company, L.P. for
approximately $89.6 million, consisting of $31.8 million in cash and $57.8
million of assumed liabilities, including debt of $33.7 million. Global
Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,
operates a network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network provides
loading, storage and unloading points for various bulk commodity imports and
exports. As of our acquisition date, we expected to invest an additional $9.4
million over the next two years to expand and upgrade the terminals, which are
located in 11 Mid-Continent states. The acquisition further expands and
diversifies our customer base and complements our existing terminal facilities
located along the lower-Mississippi River system. The acquired terminals are
included in our Terminals
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business segment. Our allocation of the purchase price to assets acquired and
liabilities assumed is preliminary, pending final purchase price adjustments
that may be necessary following an independent appraisal of fair market values.
We expect the appraisal to be completed by the end of the first quarter of 2005.
The $6.4 million of goodwill was assigned to our Terminals business segment and
the entire amount is expected to be deductible for tax purposes.
(20) Charter Products Terminals
Effective November 5, 2004, we acquired ownership interests in nine refined
petroleum products terminals in the southeastern United States from Charter
Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2
million, consisting of $72.4 million in cash and $2.8 million of assumed
liabilities. Three terminals are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South
Carolina. We fully own seven of the terminals and jointly own the remaining two.
The nine facilities have a combined 3.2 million barrels of storage. As of our
acquisition date, we expected to invest an additional $2 million over the next
two years to upgrade the facilities. All of the terminals are connected to
products pipelines owned by either Plantation Pipe Line Company or Colonial
Pipeline Company. The acquisition complements the existing terminals we own in
the Southeast and increased our southeast terminal storage capacity 76% (to 7.7
million barrels) and terminal throughput capacity 62% (to over 340,000 barrels
per day). The acquired terminals are included as part of our Products Pipelines
business segment. Our allocation of the purchase price to assets acquired and
liabilities assumed is preliminary, pending final purchase price adjustments
that may be necessary following an independent appraisal of fair market values.
We expect the appraisal to be completed by the end of the first quarter of 2005.
(21) TransColorado Gas Transmission Company
Effective November 1, 2004, we acquired all of the partnership interests in
TransColorado Gas Transmission Company from two wholly-owned subsidiaries of
KMI. TransColorado Gas Transmission Company, a Colorado general partnership
referred to in this report as TransColorado, owned assets valued at
approximately $284.5 million. As consideration for TransColorado, we paid to KMI
$211.2 million in cash and approximately $64.0 million in units, consisting of
1,400,000 common units. We also assumed liabilities of approximately $9.3
million. The purchase price for this transaction was determined by the boards of
directors of KMR and our general partner, and KMI based on valuation parameters
used in the acquisition of similar assets. The transaction was approved
unanimously by the independent members of the boards of directors of both KMR
and our general partner, and KMI, with the benefit of advice of independent
legal and financial advisors, including the receipt of fairness opinions from
separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley
& Co. TransColorado owns a 300-mile interstate natural gas pipeline that
originates in the Piceance Basin of western Colorado and runs to the Blanco Hub
in northwest New Mexico. The acquisition expanded our natural gas operations
within the Rocky Mountain region and the acquired operations are included as
part of our Natural Gas Pipelines business segment.
(22) Kinder Morgan Fairless Hills Terminal
Effective December 1, 2004, we acquired substantially all of the assets
used to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of
approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million
in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless
Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located on
the Delaware River. It is the largest port on the East Coast for the handling of
semi-finished steel slabs, which are used as feedstock by domestic steel mills.
The port operations at Fairless Hills also include the handling of other types
of steel and specialized cargo that caters to the construction industry and
service centers that use steel sheet and plate. The terminal expanded our
presence along the Delaware River and complements our existing Mid-Atlantic
terminal facilities. As of our acquisition date, we expected to invest an
additional $8.3 million in the facility. We include its operations in our
Terminals business segment.
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Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2004 and 2003, assumes that all of
the acquisitions we have made and joint ventures we have entered into since
January 1, 2003, including the ones listed above, had occurred as of January 1,
2003. We have prepared these unaudited pro forma financial results for
comparative purposes only. These unaudited pro forma financial results may not
be indicative of the results that would have occurred if we had completed these
acquisitions and joint ventures as of January 1, 2003 or the results that will
be attained in the future. Amounts presented below are in thousands, except for
the per unit amounts:
Pro Forma Year Ended
December 31,
---------------------
2004 2003
---------- ----------
(Unaudited)
Revenues................................................ $8,049,660 $6,872,721
Operating Income........................................ 1,015,229 913,716
Income Before Cumulative Effect of a Change in
Accounting Principle................................... 868,759 786,247
Net Income.............................................. $ 868,759 $ 789,712
Basic and Diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in
Accounting Principle................................ $ 2.38 $ 2.44
Net Income............................................ $ 2.38 $ 2.46
4. Change in Accounting for Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset. The provisions of this Statement are
effective for fiscal years beginning after June 15, 2002. We adopted SFAS No.
143 on January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us was to change the method of accruing for oil and gas production site
restoration costs related to our CO2 business segment. Prior to January 1, 2003,
we accounted for asset retirement obligations for this business in accordance
with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing
Companies." Under SFAS No. 143, the fair value of asset retirement obligations
are recorded as liabilities on a discounted basis when they are incurred, which
is typically at the time the assets are installed or acquired. Amounts recorded
for the related assets are increased by the amount of these obligations. Over
time, the liabilities will be accreted for the change in their present value and
the initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
o a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
o an asset retirement cost capitalized as an increase to the carrying
amount of the associated long-lived asset; and
o accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement are measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost is measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation are measured for the time period from the date the liability would
have been recognized had the provisions of this Statement been in effect to the
date of adoption of this Statement.
The cumulative effect adjustment for this change in accounting principle
resulted in income of $3.4 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative
effect adjustment resulted from the difference between the amounts
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recognized in our consolidated balance sheet prior to the application of SFAS
No. 143 and the net amount recognized in our consolidated balance sheet pursuant
to SFAS No. 143.
In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of December 31, 2004 and 2003, we have recognized
asset retirement obligations relating to these requirements at existing sites
within our CO2 segment in the aggregate amounts of $34.7 million and $32.7
million, respectively.
In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of December 31, 2004 and 2003, we have
recognized asset retirement obligations relating to the businesses within our
Natural Gas Pipelines segment in the aggregate amounts of $3.6 million and $3.0
million, respectively.
We have included $0.8 million of our total asset retirement obligations as
of both December 31, 2004 and December 31, 2003 with "Accrued other current
liabilities" in our accompanying consolidated balance sheets. The remaining
$37.5 million obligation as of December 31, 2004 and $34.9 million obligation as
of December 31, 2003 are reported separately as non-current liabilities in our
accompanying consolidated balance sheets. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of years ended December 31, 2004 and 2003 is as follows (in
thousands):
Year Ended December 31,
-------------------------------
2004 2003
------------ ------------
Balance at beginning of period..........$ 35,708 $ -
Initial ARO balance upon adoption....... - 14,125
Liabilities incurred.................... 1,157 12,911
Liabilities settled..................... (672) (1,056)
Accretion expense....................... 2,081 1,028
Revisions in estimated cash flows....... - 8,700
------------ ------------
Balance at end of period................$ 38,274 $ 35,708
============ ============
Pro Forma Information
Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):
Pro Forma Year Ended
--------------------
December 31, 2002
-----------------
(Unaudited)
Reported income before cumulative effect of a change in
accounting principle..................................... $608,377
Adjustments from change in accounting for asset retirement
obligations.............................................. (1,161)
---------
Adjusted income before cumulative effect of a change in
accounting principle..................................... $607,216
========
Reported income before cumulative effect of a change in
accounting principle per unit (fully diluted).............. $ 1.96
========
Adjusted income before cumulative effect of a change in
accounting principle per unit (fully diluted).............. $ 1.95
========
December 31,
------------
2002
------
Liability for asset retirement obligations.... $14,125
=======
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5. Income Taxes
Components of the income tax provision applicable to continuing operations
for federal, foreign and state taxes are as follows (in thousands):
Year Ended December 31,
------------------------------
2004 2003 2002
---------- ---------- -------
Taxes currently payable:
Federal............. $ 7,515 $ 437 $ 15,855
State............... 1,497 1,131 3,116
Foreign............. 70 25 147
-------- -------- ---------
Total............... 9,082 1,593 19,118
Taxes deferred:
Federal............. 5,694 11,650 (3,280)
State............... 883 1,939 (555)
Foreign............. 4,067 1,449 -
-------- -------- ---------
Total............... 10,644 15,038 (3,835)
-------- -------- ---------
Total tax provision... $ 19,726 $ 16,631 $ 15,283
======== ======== =========
Effective tax rate.... 2.3% 2.3% 2.4%
The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:
Year Ended December 31,
-------------------------
2004 2003 2002
------- ------- -------
Federal income tax rate....................... 35.0% 35.0% 35.0%
Increase (decrease) as a result of:
Partnership earnings not subject to tax..... (35.0)% (35.0)% (35.0)%
Corporate subsidiary earnings subject to tax 0.5% 0.5% 0.6%
Income tax expense attributable to corporate
equity earnings........................... 1.2% 1.5% 1.6%
Income tax expense attributable to foreign
corporate earnings........................ 0.5% 0.2% -
State taxes................................. 0.1% 0.1% 0.2%
------- ------- -------
Effective tax rate............................ 2.3% 2.3% 2.4%
======= ======= ========
Deferred tax assets and liabilities result from the following (in
thousands):
December 31,
-----------------
2004 2003
-------- -------
Deferred tax assets:
Book accruals.................................... $ 1,349 $ 1,424
Net Operating Loss/Alternative minimum tax credits 7,138 10,797
Other............................................ 1,472 -
-------- -------
Total deferred tax assets.......................... 9,959 12,221
Deferred tax liabilities:
Property, plant and equipment.................... 59,277 50,327
Other............................................ 7,169 -
-------- -------
Total deferred tax liabilities..................... 66,446 50,327
-------- -------
Net deferred tax liabilities....................... $ 56,487 $38,106
======== =======
We had available, at December 31, 2004, approximately $0.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $6.8 million of net operating loss carryforwards, which will expire between
the years 2005 and 2024. We believe it is more likely than not that the net
operating loss carryforwards will be utilized prior to their expiration;
therefore, no valuation allowance is necessary.
6. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
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December 31,
------------------------
2004 2003
----------- -----------
Natural gas, liquids and carbon dioxide pipelines....$ 3,903,021 $ 3,458,736
Natural gas, liquids and carbon dioxide
pipeline station equipment......................... 3,443,817 2,908,273
Coal and bulk tonnage transfer, storage and services. 512,024 359,088
Natural gas and transmix processing.................. 105,375 100,778
Other................................................ 511,787 330,982
Accumulated depreciation and depletion............... (947,660) (641,914)
----------- -----------
7,528,364 6,515,943
Land and land right-of-way........................... 371,172 339,579
Construction work in process......................... 269,144 236,036
----------- -----------
Property, Plant and Equipment, net...................$ 8,168,680 $ 7,091,558
=========== ===========
Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):
2004 2003 2002
------- -------- --------
Depreciation and depletion expense.... $285,351 $217,401 $171,461
7. Investments
Our significant equity investments as of December 31, 2004 consisted of:
o Plantation Pipe Line Company (51%);
o Red Cedar Gathering Company (49%);
o Thunder Creek Gas Services, LLC (25%);
o Coyote Gas Treating, LLC (Coyote Gulch) (50%);
o Cortez Pipeline Company (50%); and
o Heartland Pipeline Company (50%).
We own approximately 51% of Plantation Pipe Line Company, and an affiliate
of ExxonMobil owns the remaining approximate 49%. Each investor has an equal
number of directors on Plantation's board of directors, and board approval is
required for certain corporate actions that are considered participating rights.
Therefore, we do not control Plantation Pipe Line Company, and we account for
our investment under the equity method of accounting.
On January 1, 2002, Kinder Morgan CO2 Company, L.P. owned a 15% interest in
MKM Partners, L.P., a joint venture with Marathon Oil Company. The remaining 85%
interest in MKM Partners was owned by subsidiaries of Marathon Oil Company. The
joint venture assets consisted of a 12.75% interest in the SACROC oil field unit
and a 49.9% interest in the Yates field unit, both of which are in the Permian
Basin of West Texas. We accounted for our 15% investment in the joint venture
under the equity method of accounting because our ownership interest included
50% of the joint venture's general partner interest, and the ownership of this
general partner interest gave us the ability to exercise significant influence
over the operating and financial policies of the joint venture. Effective June
1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the
SACROC unit for $23.3 million and the assumption of $1.9 million of liabilities.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P. The partnership's dissolution was
effective June 30, 2003, and the net assets were distributed to partners in
accordance with its partnership agreement. Our interests in the SACROC unit and
the Yates field unit, including the incremental interest acquired in November
2003, are accounted for using the proportional method of consolidation for oil
and gas operations.
In September 2003, we paid $10.0 million to acquire reversionary interests
in the Red Cedar Gas Gathering Company. The 4% reversionary interests were held
by the Southern Ute Indian Tribe and were scheduled to take effect September 1,
2004 and September 1, 2009. With the elimination of these reversions, our
ownership interest in Red Cedar will be maintained at 49% in the future. For
more information on our acquisitions, see Note 3.
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Our total investments consisted of the following (in thousands):
December 31,
-------------------
2004 2003
-------- --------
Plantation Pipe Line Company........................... $216,142 $219,349
Red Cedar Gathering Company............................ 124,209 114,176
Thunder Creek Gas Services, LLC........................ 37,122 37,245
Cortez Pipeline Company................................ 15,503 12,591
Coyote Gas Treating, LLC............................... 12,964 13,502
Heartland Pipeline Company............................. 5,106 5,109
All Others............................................. 2,209 2,373
-------- --------
Total Equity Investments............................... $413,255 $404,345
======== ========
Our earnings from equity investments were as follows (in thousands):
Year Ended December 31,
-------------------------------
2004 2003 2002
-------- -------- --------
Cortez Pipeline Company............. $ 34,179 $ 32,198 $ 28,154
Plantation Pipe Line Company........ 25,879 27,983 26,426
Red Cedar Gathering Company......... 14,679 18,571 19,082
Thunder Creek Gas Services, LLC..... 2,828 2,833 2,154
Coyote Gas Treating, LLC............ 2,453 2,608 2,651
Heartland Pipeline Company.......... 1,369 973 998
MKM Partners, L.P................... - 5,000 8,174
All Others.......................... 1,803 2,033 1,619
-------- -------- --------
Total............................... $ 83,190 $ 92,199 $ 89,258
======== ======== ========
Amortization of excess costs........ $ (5,575) $ (5,575) $ (5,575)
======== ======== ========
Summarized combined unaudited financial information for our significant
equity investments (listed above) is reported below (in thousands; amounts
represent 100% of investee financial information):
Year Ended December 31,
--------------------------------
Income Statement 2004 2003 2002
---------------------------------- --------- -------- ---------
Revenues...................................... $ 418,186 $467,871 $ 505,602
Costs and expenses............................ 265,819 295,931 309,291
--------- -------- ---------
Earnings before extraordinary items and
cumulative effect of a change in accounting
principle................................... 152,367 171,940 196,311
========= ======== =========
Net income.................................... $152,367 $168,167 $196,311
========= ======== =========
December 31,
----------------------
Balance Sheet 2004 2003
-------------------------- ----------- ----------
Current assets............ $ 107,954 $ 93,709
Non-current assets........ 696,493 684,754
Current liabilities....... 218,922 377,535
Non-current liabilities... 364,406 209,468
Partners'/owners' equity.. $ 221,119 $ 191,460
8. Intangibles
Under ABP No. 18, any premium paid by an investor, which is analogous to
goodwill, must be identified. Under prior rules, excess cost over underlying
fair value of net assets accounted for under the equity method, referred to as
equity method goodwill, would have been amortized, however, under SFAS No. 142,
equity method goodwill is not subject to amortization but rather to impairment
testing pursuant to ABP No. 18. The impairment test under APB No. 18 considers
whether the fair value of the equity investment as a whole, not the underlying
net assets, has declined and whether that decline is other than temporary. This
test requires equity method investors to continue to assess impairment of
investments in investees by considering whether declines in the fair values of
those investments, versus carrying values, may be other than temporary in
nature. The caption "Investments" in our accompanying consolidated balance
sheets includes $150.3 million of equity method goodwill as of both December 31,
2004, and December 31, 2003.
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Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):
December 31,
--------------------
2004 2003
--------- ---------
Goodwill
Gross carrying amount...... $ 746,980 $ 743,652
Accumulated amortization... (14,142) (14,142)
--------- ---------
Net carrying amount........ 732,838 729,510
--------- ---------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (1,028) (888)
--------- ---------
Net carrying amount........ 5,564 5,704
--------- ---------
Contracts and other
Gross carrying amount...... 10,775 7,801
Accumulated amortization... (1,055) (303)
--------- ---------
Net carrying amount........ 9,720 7,498
--------- ---------
Total intangibles, net..... $ 748,122 $ 742,712
========= =========
<TABLE>
<CAPTION>
Changes in the carrying amount of goodwill for each of the two years ended
December 31, 2003 and 2004 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Balance as of December 31, 2002... $ 263,182 $ 253,358 $ 46,101 $ 153,969 $ 716,610
Goodwill acquired............... - - - 12,900 12,900
Impairments..................... - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2003... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
Goodwill acquired............... - - - 6,368 6,368
Disposals - purchase price adjs. - (3,040) - - (3,040)
Impairments..................... - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2004... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838
=========== =========== =========== =========== ===========
</TABLE>
Amortization expense on intangibles consists of the following (in thousands):
Year Ended December 31,
---------------------------
2004 2003 2002
-------- -------- --------
Goodwill................. $ - $ - $ -
Lease value.............. 140 140 140
Contracts and other...... 752 64 40
-------- ------- --------
Total amortization....... $ 892 $ 204 $ 180
======== ======= ========
As of December 31, 2004, our weighted average amortization period for our
intangible assets is approximately 24 years. Our estimated amortization expense
for these assets for each of the next five fiscal years is approximately $1.0
million.
Had SFAS No. 142 been in effect prior to January 1, 2002, our limited
partners' interest in net income and net income per unit would not have differed
from the reported amounts.
9. Debt
Our debt and credit facility as of December 31, 2004, consisted primarily
of:
o a $1.25 billion unsecured five-year credit facility due August 18, 2009;
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o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2006 (our 66 2/3% owned
subsidiary, International Marine Terminals, is the obligor on the
bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $20 million of 7.84% Senior Notes, with a final maturity of July 2008
(our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
notes);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $5.3 million of Illinois Development Revenue Bonds due January 1, 2010
(our subsidiary, Arrow Terminals L.P., is the obligor on the bonds);
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $500 million of 5.00% Senior Notes due December 15, 2013;
o $500 million of 5.125% Senior Notes due November 15, 2014;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds
due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due April 1, 2024 (our subsidiary,
Kinder Morgan Operating L.P. "B," is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $1.25 billion short-term commercial paper program (supported by our
credit facility, the amount available for borrowing under our credit
facility is reduced by our outstanding commercial paper borrowings).
Our outstanding short-term debt as of December 31, 2004 was $621.2 million.
The balance consisted of:
o $416.9 million of commercial paper borrowings;
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $5 million under the Central Florida Pipeline LLC Notes; and
o an offset of $0.7 million (which represents the net of other
borrowings and the accretion of discounts on our senior note
issuances).
As of December 31, 2004, we intended and had the ability to refinance all
of our short-term debt on a long-term basis under our unsecured long-term credit
facility. Accordingly, such amounts have been classified as long-term debt in
our accompanying consolidated balance sheet. The weighted average interest rate
on all of our borrowings was approximately 4.4702% during 2004 and 4.4924%
during 2003.
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Credit Facilities
As of December 31, 2002, we had two outstanding credit facilities. The two
facilities consisted of a $530 million unsecured 364-day credit facility due
October 14, 2003, and a $445 million unsecured three-year credit facility due
October 15, 2005. There were no borrowings under either credit facility as of
December 31, 2002.
On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:
o our $530 million unsecured 364-day credit facility was increased to
$570 million; and
o our $445 million unsecured three-year credit facility was increased to
$480 million.
Our $570 million unsecured 364-day credit facility expired October 14,
2003. On that date, we obtained a new $570 million unsecured 364-day credit
facility due October 12, 2004. As of December 31, 2003, we had two credit
facilities totaling $1.05 billion in committed credit lines, consisting of the
$570 million unsecured 364-day credit facility due October 12, 2004, and the
$480 million unsecured three-year credit facility due October 15, 2005. There
were no borrowings under either credit facility as of December 31, 2003.
On August 18, 2004, we replaced our existing bank facilities with a $1.25
billion five-year, unsecured revolving credit facility due August 18, 2009.
Similar to our previous credit facilities, our current credit facility is with a
syndicate of financial institutions and Wachovia Bank, National Association is
the administrative agent. There were no borrowings under our five-year credit
facility as of December 31, 2004.
Our five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate. Interest on our credit facility
accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.
The amount available for borrowing under our credit facility as of December
31, 2004 was reduced by:
o our outstanding commercial paper borrowings ($416.9 million as of
December 31, 2004);
o a $50 million letter of credit that supports our hedging of commodity
price risks involved from the sale of natural gas, natural gas
liquids, oil and carbon dioxide;
o a $25.9 million letter of credit entered into on December 23, 2002
that supports Nassau County, Florida Ocean Highway and Port Authority
tax-exempt bonds (associated with the operations of our bulk terminal
facility located at Fernandina Beach, Florida);
o a $24.1 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;
o a $1 million letter of credit entered into on December 13, 2004 that
supports a workers' compensation insurance policy;
o a $0.3 million letter of credit entered into on December 3, 2004 that
supports an equipment rental obligation related to our bulk terminal
facility located at Fairless Hills, Pennsylvania; and
o a $0.2 million letter of credit entered into on June 4, 2003 that
supports a workers' compensation insurance policy.
Our credit facility included the following restrictive covenants as of
December 31, 2004:
o requirements to maintain certain financial ratios:
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o total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may not
exceed 5.0;
o total indebtedness of all consolidated subsidiaries shall at no time
exceed 15% of consolidated indebtedness; and
o consolidated indebtedness shall at no time exceed 62.5% of total
capitalization;
o certain limitations on entering into mergers, consolidations and sales
of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an
event of default exists or would exist upon making such distribution.
In addition to normal repayment covenants, under the terms of our credit
facility, the occurrence at any time of any of the following would constitute an
event of default:
o our failure to make required payments of any item of indebtedness or
any payment in respect of any hedging agreement, provided that the
aggregate outstanding principal amount for all such indebtedness or
payment obligations in respect of all hedging agreements is equal to
or exceeds $75 million;
o our general partner's failure to make required payments of any item of
indebtedness, provided that the aggregate outstanding principal amount
for all such indebtedness is equal to or exceeds $75 million;
o adverse judgments rendered against us for the payment of money in an
aggregate amount in excess of $75 million, if this same amount remains
undischarged for a period of thirty consecutive days during which
execution shall not be effectively stayed; and
o voluntary or involuntary commencements of any proceedings or petitions
seeking our liquidation, reorganization or any other similar relief
under any federal, state or foreign bankruptcy, insolvency,
receivership or similar law.
Excluding the relatively non-restrictive specified negative covenants and
events of defaults, our credit facility does not contain material adverse change
clauses or any provisions designed to protect against a situation where a party
to an agreement is unable to find a basis to terminate that agreement while its
counterparty's impending financial collapse is revealed and perhaps hastened
through the default structure of some other agreement.
None of our debt is subject to payment acceleration as a result of any
change to our credit ratings. However, the margin that we pay with respect to
LIBOR-based borrowings under our credit facility varies with our credit ratings.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 14.
Commercial Paper Program
As of December 31, 2003, our commercial paper program provided for the
issuance of up to $1.05 billion of commercial paper, and on that date, we had
$426.1 million of commercial paper outstanding with an average interest rate of
1.1803%. On October 15, 2004, we increased our commercial paper program by $200
million to provide for the issuance of up to $1.25 billion. Our $1.25 billion
unsecured 5-year credit facility supports our commercial paper program, and
borrowings under our commercial paper program reduce the borrowings allowed
under our credit facility. As of December 31, 2004, we had $416.9 million of
commercial paper outstanding with an average interest rate of 2.2856%. The
borrowings under our commercial paper program were used principally to finance
the acquisitions we made during 2003 and 2004.
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Senior Notes
On November 21, 2003, we closed a public offering of $500 million in
principal amount of 5% senior notes due December 15, 2013 at a price to the
public of 99.363%. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $493.6 million. We used the proceeds
to reduce the outstanding balance of our commercial paper borrowings.
On November 12, 2004, we closed a public offering of $500 million in
principal amount of 5.125% senior notes due November 15, 2014 at a price to the
public of 99.914%. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $496.3 million. We used the proceeds
to reduce the outstanding balance on our commercial paper borrowings.
As of December 31, 2004, the outstanding balance on the various series of
our senior notes was as follows (in millions):
8.00% senior notes due March 15, 2005...... $ 200.0
5.35% senior notes due August 15, 2007..... 249.9
6.30% senior notes due February 1, 2009.... 249.7
7.50% senior notes due November 1, 2010.... 249.1
6.75% senior notes due March 15, 2011...... 698.7
7.125% senior notes due March 15, 2012..... 448.5
5.00% senior notes due December 15, 2013... 497.2
5.125% senior notes due November 15, 2014.. 499.6
7.40% senior notes due March 15, 2031...... 299.3
7.75% senior notes due March 15, 2032...... 298.6
7.30% senior notes due August 15, 2033..... 499.0
---------
Total.................................... $ 4,189.6
=========
SFPP, L.P. Debt
In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding
under its Series F notes, plus $2.0 million for interest, as a result of its
taking advantage of certain optional prepayment provisions without penalty. The
annual interest rate on the Series F notes was 10.70%, the maturity was December
2004, and interest was payable semiannually in June and December. We had agreed
as part of the acquisition of SFPP, L.P.'s operations (which constitute a
significant portion of our Pacific operations) not to take actions with respect
to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences
for the prior general partner of SFPP, L.P. The Series F notes were
collateralized by mortgages on substantially all of the properties of SFPP, L.P.
and contained certain covenants limiting the amount of additional debt or equity
that may be issued by SFPP, L.P. and limiting the amount of cash distributions,
investments, and property dispositions by SFPP, L.P.
Kinder Morgan Wink Pipeline, L.P. Debt
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., whi